UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |
For the Fiscal Year Ended December 31, | ||
Or | ||
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||
For the transition period from |
Commission File Number | Exact Name of Registrant as specified in its charter | State or Other Jurisdiction of Incorporation or Organization | IRS Employer Identification Number | |||
1-12609 | PG&E CORPORATION | California | 94-3234914 | |||
1-2348 | PACIFIC GAS AND ELECTRIC COMPANY | California | 94-0742640 |
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77 Beale Street, P.O. Box 770000 San Francisco, California (Address of principal executive offices) (Zip Code) (415) 267-7000 ( | ![]() | 77 Beale Street, P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code) (415) 973-7000 ( |
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
PG&E Corporation:Common Stock, no par value | New York Stock Exchange | |
Pacific Gas and Electric Company:First Preferred Stock, cumulative, par value $25 per share: | NYSE | |
Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36% | ||
Nonredeemable: 6%, 5.50%, 5% |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
PG&E Corporation | Yes | |||
Pacific Gas and Electric Company | Yes |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
PG&E Corporation | Yes | |||
Pacific Gas and Electric Company | Yes |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
PG&E Corporation | Yes | |||
Pacific Gas and Electric Company | Yesþ No¨ |
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
PG&E Corporation | Yes | |||
Pacific Gas and Electric Company | Yes þ No ¨ |
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant'sregistrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:
PG&E Corporation | þ | |||
Pacific Gas and Electric Company | þ |
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):
PG&E Corporation | Pacific Gas and Electric Company | |
Large accelerated filer | Large accelerated filer | |
Accelerated filer | Accelerated filer | |
Non-accelerated filer | Non-accelerated filer | |
Smaller reporting company | Smaller reporting company |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation | Yes | |||
Pacific Gas and Electric Company | Yes |
Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2008,2011, the last business day of the most recently completed second fiscal quarter:
PG&E Corporation | $ | |
Pacific Gas and Electric Company | Wholly owned by PG&E Corporation |
Common Stock outstanding as of February 7, 2012:
PG&E Corporation: | 412,899,635 shares | |||
Pacific Gas and Electric Company: | 264,374,809 shares (wholly owned by PG&E Corporation) |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
Designated portions of the combined Shareholders | Part I (Items 1 and 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 9A) |
Designated portions of the Joint Proxy Statement relating to the Annual Meetings of Shareholders | Part III (Items 10, 11, 12, 13 and 14) |
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1 Kilowatt (kW) | = | One thousand watts | ||||
1 Kilowatt-Hour (kWh) | = | One kilowatt continuously for one hour | ||||
1 Megawatt (MW) | = | One thousand kilowatts | ||||
1 Megawatt-Hour (MWh) | = | One megawatt continuously for one hour | ||||
1 Gigawatt (GW) | = | One million kilowatts | ||||
1 Gigawatt-Hour (GWh) | = | One gigawatt continuously for one hour | ||||
1 Kilovolt (kV) | = | One thousand volts | ||||
1 MVA | = | One megavolt ampere | ||||
1 Mcf | = | One thousand cubic feet | ||||
1 MMcf | = | One million cubic feet | ||||
1 Bcf | = | One billion cubic feet | ||||
1 MDth | = | One thousand decatherms |
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PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporationthat conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.
The Utility’s revenues are generated mainly through the sale and delivery of electricity and natural gas to customers. The Utility served approximately 5.15.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2008.2011. The Utility had approximately $40.5$49.2 billion ofin assets at December 31, 20082011 and generated revenues of approximately $14.6$15 billion in 2008. Its revenues are generated mainly through the sale and delivery of electricity and natural gas.2011. The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”).
The principal executive officeoffices of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility isare located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and itstheir telephone number is (415) 973-7000. PG&E Corporation and the Utility file or furnish various reports with the Securities and Exchange Commission (“SEC”). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (“1934 Act”), are available free of charge on both PG&E Corporation'sCorporation’s website,www.pgecorp.com, and the Utility'sUtility’s website,www.pge.com., as promptly as practicable after they are filed with, or furnished to, the SEC. The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.
This is a combined Annual Report on Form 10-K of PG&E Corporation and the Utility and includes information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2011 (“2011 Annual Report”) and the Joint Proxy Statement relating to the 2012 Annual Meetings of Shareholders.
At December 31, 2008,2011, PG&E Corporation and its subsidiaries had approximately 21,66719,274 regular employees, including approximately 21,45119,253 regular employees of the Utility. Of the Utility'sUtility’s regular employees, approximately 14,64911,950 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC (“ESC”); and the Service Employees International Union, Local 24/7 (“SEIU”). There are two collective bargaining agreements with IBEW. One IBEW collective bargaining agreement expireswas scheduled to expire on December 31, 2011 andbut will remain in effect until the earlier of the date that IBEW members ratify a new agreement or December 31, 2012. The other IBEW collective bargaining agreement expireswill expire on December 31, 2010.2015. The ESC collective bargaining agreement expireswas scheduled to expire on December 31, 2009. The Utility and the ESC reached an agreement2011 but will remain in January 2009 to extend the collective bargaining agreementeffect until December 31, 2011, subject2012, unless a new agreement becomes effective before then. The ESC and the Utility are negotiating the terms of a new agreement and hope to ratificationcomplete negotiations by the end of February 2012. The proposed new agreement would then be sent to ESC members of the ESC.for ratification. The SEIU collective bargaining agreement expires on July 31, 2009.
After the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”), various civil lawsuits, regulatory investigations and proceedings, and a criminal investigation were commenced. The Utility has stated publicly that it is liable for the San Bruno accident and it will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident. In June 2011, an independent review panel appointed by the CPUC to investigate the San Bruno accident issued a report that was highly critical of the Utility’s natural gas operating practices and procedures, including its risk management and pipeline integrity programs, and its corporate culture. In August 2011, the National Transportation Safety Board (“NTSB”) announced that it had determined the probable cause of the San Bruno accident placing the blame primarily on the Utility. In January 2012, the CPUC’s Consumer Protection and Safety Division (“CPSD”) issued its report containing the findings of its investigation into the San Bruno accident and alleging that the Utility committed numerous violations in connection with the San Bruno accident. The CPUC has commenced three investigations pertaining to the Utility’s natural gas transmission operations, including an investigation of the San Bruno accident to consider the CPSD’s allegations. (See Item 3. Legal Proceedings, below.) The CPUC has also delegated to its staff the authority to issue citations and impose penalties for violation of the natural gas regulations and rules. On January 27, 2012, the CPSD exercised this new authority to issue a citation and impose a penalty of approximately $17 million on the Utility for self-reported violations of these rules. PG&E Corporation and the Utility have concluded that it is probable that the Utility will be required to pay penalties associated with these matters and have accrued an amount in their financial statements reflecting the reasonably estimable minimum amount of penalties they believe it is probable that the Utility will incur.
For more information about these investigations and related matters see “Natural Gas Matters” within the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) in the 2011 Annual Report.
This combined Annual Report on Form 10-K, including the information incorporated by reference from the joint2011 Annual Report and the Joint Proxy Statement relating to Shareholders for the year ended December 31, 2008 (“20082012 Annual Report”),Meetings of Shareholders, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management'smanagement’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation, tax, and other liabilities, estimated tax liabilities,estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies, the anticipated outcome of various regulatory, governmental, and legal proceedings, estimated losses and insurance recoveries associated with the San Bruno accident, estimated additional costs the Utility will incur related to its natural gas transmission and distribution business; estimated future cash flows, and the level of future equity or debt issuances, andissuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim, “” “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:
the outcome of pending and future investigations and regulatory proceedings related to the San Bruno accident, and the safety of the Utility’s natural gas transmission pipelines in its service territory; the ultimate amount of costs the Utility incurs for natural gas matters that are not recovered through rates; the ultimate amount of third-party claims associated with the San Bruno accident that are not recovered through insurance; and the amount of any civil or criminal penalties, or punitive damages, the Utility may incur related to these matters, including the amount of penalties that the CPSD may impose on the Utility for violations of natural gas safety regulations;
the outcome of future investigations or proceedings that may be commenced by the CPUC or other regulatory authorities relating to the Utility’s compliance with law, rules, regulations, or orders applicable to the operation, inspection, and maintenance of its electric and gas facilities (in addition to investigations or proceedings related to the San Bruno accident and natural gas matters);
whether PG&E Corporation and the Utility are able to repair the reputational harm they have suffered which, in part, will depend on their ability to adequately and timely respond to the findings and recommendations made by the NTSB and CPUC’s independent review panel and cure the deficiencies that have been identified in the Utility’s operating practices and procedures and corporate culture; developments that may occur in the various investigations of the San Bruno accident and natural gas matters; the decisions, findings, or orders issued in connection with these investigations, including the amount of civil or criminal penalties that may be imposed on the Utility, developments that may occur in the civil litigation related to the San Bruno accident; and the extent of service disruptions that may occur due to changes in pipeline pressure as the Utility continues to inspect and test pipelines;
the adequacy and price of electricity and natural gas supplies, the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and the availability and price of nuclear fuel used in the two nuclear generation units at Diablo Canyon;
explosions, fires, accidents, mechanical breakdowns, equipment failures, human errors, labor disruptions, and similar events, as well as acts of terrorism, war, or vandalism, including cyber-attacks, that can cause unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies, and subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;
the impact of storms, tornados, floods, drought, earthquakes, tsunamis, wildland and other fires, pandemics, solar events, electromagnetic events, and other natural disasters, or that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;
the potential impacts of climate change on the Utility’s electricity and natural gas businesses, the impact of environmental laws and regulations aimed at the reduction of carbon dioxide and other greenhouse gases (“GHG”) on the Utility’s electricity and natural gas businesses, and whether the Utility is able to recover associated compliance costs including the cost of emission allowances and offsets that the Utility may incur under cap and trade regulations;
changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline in the Utility’s service area, general and regional economic and financial market conditions, the development of alternative energy technologies including self-generation and distributed generation technologies, or other reasons;
the occurrence of unplanned outages at the Utility’s large hydroelectric or nuclear generation facilities and the ability of the Utility to procure replacement electricity if hydroelectric or nuclear generation operations were unavailable;
the results of seismic studies the Utility is conducting that could affect the Utility’s ability to continue operating Diablo Canyon or renew the operating licenses for Diablo Canyon, the impact of new NRC orders or regulations to implement various recommendations made by the NRC’s task force following the March 2011 earthquake and tsunami in Japan that caused significant damage to nuclear facilities in Japan, and the impact of new legislation, regulations, or policies that may be adopted in the future to address the operations, security, safety, or decommissioning of nuclear facilities, the storage of spent nuclear fuel, seismic design, cooling water intake, or other issues;
the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company, and whether the outcome of proceedings and investigations relating to the Utility’s natural gas operations affects the Utility’s ability to make distributions to PG&E Corporation in the form of dividends or share repurchases;
whether the Utility’s | ||
generate billing information, whether the | ||
rely on third-party vendors and contractors to support the | ||
whether the Utility is able to protect its information technology, operating systems and networks, including the advanced metering system infrastructure, from damage, disruption, or failure caused by cyber-attacks, computer viruses, and other hazards; and whether the Utility’s security measures are sufficient to protect the confidential customer, vendor and financial data contained in such systems and networks from unauthorized access and disclosure;
the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, that are not recoverable through insurance, rates, or from other third parties;
the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;
the impact of environmental remediation laws, regulations, and orders; the extent to which the Utility is able to recover compliance and remediation costs from third parties or through rates or insurance, and the ultimate amount of environmental remediation costs the Utility incurs in connection with its natural gas compressor station located near Hinkley, California which are not recoverable through insurance or rates;
the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits certain types of governmental bodies to purchase and sell electricity for their local residents and businesses; and
the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010.
For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the section of MD&A entitled “Risk Factors” in the 2011 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.
For more information about the significant risks that could affect PG&E Corporation and the Utility's future financial condition and results of operations, see the discussion under “Risk Factors” that appears near the end of the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) in the 2008 Annual Report.
As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005 (“EPAct”), which became effective on February 8, 2006. Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”PUHCA”). Under the PUHCA, 2005, public utility holding companies fall principally under the regulatory oversight of the FERC, an independent agency within the U.S. Department of Energy (“DOE”).FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of the PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.
PG&E Corporation is not a public utility under California law. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:
the Utility cannot guarantee any obligations of |
the Utility’s dividend policy must be established by the Utility’s Board of Directors as well asthough the directorsUtility were a stand-alone utility company;
the capital requirements of the Utility, violatedas determined to be necessary and prudent to meet the CPUC’s holding company conditions during the California 2000-2001 energy crisis. PG&E Corporation andUtility’s obligation to serve or to operate the Utility believe that they have complied with applicable statutes, CPUC decisions, rulesin a prudent and orders.)efficient manner, must be given first priority by PG&E Corporation’s Board of Directors (known as the “first priority” condition); and
the Utility must maintain on average its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility’s common equity component by 1% or more.
The CPUC also has adopted complex and detailed rules governing transactions between California'sCalifornia’s electricity and gas utilities and certain of their affiliates. The rules address the use of the utilities’ names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates. The rules also also:
prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility's affiliates. In December 2006,utility’s affiliates;
emphasize that the CPUC revised itsholding company may not aid or abet a utility’s violation of the rules or act as a conduit to among other changes:provide confidential utility information to an affiliate;
require prior CPUC approval before the utility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the other party is not known until the transaction is consummated; |
require certain key officers to provide annual certifications of compliance with the affiliate rules;
prohibit certain key officers from serving in the same position at both the utility and the holding company (unless otherwise permitted by the CPUC), or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the provision of permitted shared services);
require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and
make the CPUC’s Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the utility is in compliance with the affiliate rules.
The CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.
Various aspects of the Utility'sUtility’s business are subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938 and the Public Utility Regulatory Policies Act of 1978 (“PURPA”).
For discussion of specific pending regulatory proceedings and investigations that are expected to affect the Utility, see the sectionsections of MD&A entitled “Regulatory Matters” and “Natural Gas Matters” in the 20082011 Annual Report.
The FERC regulates the transmission of electricity and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities;facilities, tariffs and conditions of service of regional transmission organizations, including the CAISO;California Independent System Operator Corporation (“CAISO”), and the terms and rates of wholesale electricity sales. The EPAct granted the FERC significant new responsibilities to oversee the reliability of the nation’s electricity transmission grid, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The EPAct also expanded the FERC’shas authority to impose penalties of up to $1,000,000 per day for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. The FERC can impose penalties of up to $1,000,000 per day per violation. The FERC has jurisdiction over the Utility'sUtility’s electricity transmission annual amount of revenue requirements(“revenue requirements”) and rates, the licensing of substantially all of the Utility'sUtility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas.
Electric Reliability Standards; Development of Transmission Grid. As partThe FERC has the responsibility to approve and enforce mandatory standards governing the reliability of its directive to oversee the development of mandatory electric reliabilitynation’s electricity transmission grid, including standards to protect the nationalnation’s bulk power system against potential disruptions from cyber and physical security breaches, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission system, thecorridors that are determined to be of national interest. The FERC certified the North American Electric Reliability Corp.Corporation (“NERC”), as the nation’s Electric Reliability Organization under the EPAct of 2005.Organization. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council (“WECC”). The Utility must self-certify compliance to the WECC on an annual basis and the compliance program encourages self-reporting of violations. WECC staff, with participation by the NERC and the FERC, will also performperforms a regular compliance audit of the Utility every three years. In addition, the WECC and the NERC may perform spot checks or other interim audits, reports, or investigations. Under FERC authority, the WECC, NERC, and/or FERC may impose penalties up to $1,000,000 per day per violation.
The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk. In addition, pursuant to FERC orders, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.
On July 21, 2011, the FERC adopted Order No. 1000, its final rule on transmission planning and cost allocation requirements. Order No. 10000 is intended to benefit consumers by: (1) enhancing the grid’s ability to support wholesale power markets and transmit renewable energy supplies; and (2) ensuring transmission services are provided at just and reasonable rates. Order No. 1000 requires public utility transmission providers to improve transmission planning processes and allocate costs for new transmission facilities to the beneficiaries of those facilities. The transmission planning requirements established in the rule include development of regional transmission plans, consideration of transmission needs driven by public policy requirements established by state or federal laws or regulations, and coordination between pairs of neighboring transmission planning regions. The cost allocation requirements established in the rule include development of regional and interregional cost allocation methods. (Under the rule, participant-funding of new transmission facilities is permitted, but cannot be used as the regional or interregional cost allocation method.) The rule also directs that provisions granting rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation be removed from FERC-approved tariffs.
The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”). NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.
The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. UnderIn November 2009, the termsUtility filed an application at the NRC to begin the license renewal process which is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. At the Utility’s request, the NRC has agreed to delay processing the Utility’s application until the Utility completes extensive seismological studies in 2015 or 2016.
Following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan, the NRC appointed a task force to develop recommendations about how to improve safety at U.S. nuclear power plants and upgrade protection against earthquakes, floods and power losses. The twelve safety recommendations were released in July 2011 and have been reviewed by the NRC staff. During 2012, it is expected that the NRC will adopt regulations or issue orders requiring nuclear power plants to implement some of these licenses, there must be sufficient storage capacitythe near-term recommendations. The NRC is expected to implement the remaining recommendations over the next five years.
For more information about the relicensing proceeding and other matters affecting Diablo Canyon, see the section of MD&A in the 2011 Annual Report entitled “Regulatory Matters–Diablo Canyon Nuclear Power Plant.”
The Pipeline and Hazardous Materials Safety Administration
The Utility also is subject to regulations adopted by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the radioactive spent fuel produced by the Diablo Canyon plant. For a discussionsafe, reliable, and environmentally sound operation of the Utility’s spent fuel storage project, see “Environmental Matters – Nuclear Fuel Disposal,” below.
The NTSB is an independent federal agency that is authorized to investigate pipeline accidents and certain transportation accidents that involve fatalities, substantial property damage, or significant environmental damage. On September 26, 2011, the NTSB released its final investigative report on the San Bruno accident. (See the section of MD&A entitled “Natural Gas Matters” in the 2011 Annual Report for more information.)
The federal Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 became effective on January 3, 2012 (the “Pipeline Safety Act”). In addition to re-authorizing funds for PHMSA’s pipeline safety programs through 2015, this act requires the Secretary of the Department of Transportation to review and evaluate certain existing pipeline safety regulations. Among other requirements, the Pipeline Safety Act requires the Secretary to examine the sufficiency of certain safety regulations and whether to adopt various NTSB recommendations made following its investigation of several natural gas incidents, including the San Bruno accident. The Secretary is authorized under specific circumstances, some of which require an evaluation and a Congressional review period, to adopt regulations to address pipeline integrity management requirements, leak detection systems, the use of automatic or remote-controlled shut-off valves, verification of pipeline records to ensure that records reflect actual pipeline characteristics, and to conduct testing to confirm the strength of certain previously untested pipelines in high consequence areas. The Pipeline Safety Act also increases the maximum civil penalties for violation of safety rules from $100,000 to $200,000 for an individual violation and from $1,000,000 to $2,000,000 for a series of violations.
The Utility'sUtility’s operations have been significantly affected by various statutes passed by the California Legislature, including:
In April 2011, the California Governor signed new legislation establishing a new renewable portfolio standard (“RPS”) that increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales. For more information see “Renewable Energy Resources” below.
In addition, several laws were enacted during 2011 to expand the authority of the CPUC to order the gas utilities to make improvements to the natural gas transmission system in California, including ordering the utilities to install automatic or remote shut-off valves on certain pipelines and to comply with new emergency preparedness and emergency response standards and procedures.
Also, effective January 1, 2012, the CPUC’s authority to impose penalties for violating laws, orders, or regulations has increased from $20,000 per violation, per day, to $50,000 per violation, per day.
The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms. The CPUC has jurisdiction to setover the rates and terms and conditions of service for the Utility'sUtility’s electricity distribution, electricity generation,and natural gas distribution operations, electricity generation, and natural gas transportation and storage services in California.services. The CPUC also has jurisdiction over the Utility'sUtility’s issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility'sUtility’s electricity and natural gas retail customers, raterates of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.
The CPUC also enforces laws that set forth safety requirements pertaining to the electricitydesign, construction, testing, operation, and maintenance of utility gas gathering, transmission, system. and distribution pipeline systems, and for the safe operation of such pipelines and equipment. The CPUC also has been delegated authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities.
Ratemaking for retail sales from the Utility'sUtility’s generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.
PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility'sUtility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001 referred to as the (“Chapter 11 Settlement Agreement.Agreement”). The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters. (For more information, see Note 15 of the Notes to the Consolidated Financial Statements included in the 2008 Annual Report.)
The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (“CEC”), is the state'sstate’s primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new, and emerging renewable technologies. In addition, the CEC is responsible for forecastingforecasts of future energy needs used by the CPUC in determining the adequacy of the utilities'utilities’ electricity procurement plans.
The California Air Resources Board
The California Air Resources Board (“CARB”) is the state agency charged with setting and monitoring GHG and other emission limits. The CARB also is responsible for adopting and enforcing regulations to meet California’s landmark law, the California Global Warming Solutions Act of 2006 (“AB 32”), which requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. In October 2011, the CARB adopted its final “cap-and-trade” regulations to help gradually reduce GHG emissions. (For more information see “Environmental Matters — Air Quality and Climate Change” below.)
The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility'sUtility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. DischargeThese permits include discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples.licenses. Some licenses and
The Utility has over 520 franchise agreements with various292 cities and counties that permit the Utility to install, operate, and maintain the Utility'sUtility’s electric and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In addition, charter cities can negotiate their fees. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term of years, including an agreement with a large charter city. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations, and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility'sUtility’s business and to conduct certain related operations.
Federal. At the federal level, manyMany provisions of the EPActEnergy Policy Act of 2005 (“EPAct”) support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. (See the section above entitled “The Utility’s Regulatory Environment–Federal Energy Regulation” for a description of some of these rules.) The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.
Even before the passage of the EPAct, the FERC'sFERC’s policies supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities'utilities’ transmission grids. Order 888 requires all public utilities that own, control, or operate, facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service. The FERC'sFERC’s subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination;discrimination, (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement;enforcement, and (3) increase transparency in the rules applicable to planning and use of the transmission system.
The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation
State. At the state level, California Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry commencingbeginning in 1998.1998 to allow customers of the California investor-owned electric utilities to purchase energy from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as “direct access”). Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted through the Power Exchange (“PX”). As a result ofFollowing the 2000-2001 California 2000-2001 energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile
remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC. (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utility’s Chapter 11 proceeding, see Note 1513: Resolution of Remaining Chapter 11 Disputed Claims, of the Notes to the Consolidated Financial Statements in the 20082011 Annual Report.) The CAISO, which was established pursuant to AB 1890 to take control of
During the 2000-2001 energy crisis, the California investor-owned electric transmission facilities located in California, currently administers a real-time or “spot” wholesale market for the sale of electric energy. This market is used to allocate space on the transmission lines, maintain operating reserves, and match supply with demand in real time. The CAISO’s MRTU initiative is intended to restructureLegislature authorized the California Department of Water Resources (“DWR”), beginning on February 1, 2001, to purchase electricity market and sell that electricity directly to enhance power grid reliability, including the implementation of a new day-ahead market. The CAISO also will provide congestion revenue rights to allow market participants, including load-serving entities, to hedgeutilities’ retail customers. (The utilities deliver electricity purchased by the financial risk of CAISO-imposed congestion charges inDWR under the MRTU day-ahead market. The MRTU tariffs will apply to all load-serving entities, includingcontracts and act as the investor-owned utilities, serving California consumers. The CAISO has delayed the start date of MRTU several times but is now targeting April 1, 2009. Also, in January 2008, the CPUC staff issued its recommendation to establish a statewide wholesale electric capacity market to replace the current resource adequacy program. Any changes the CPUC adopts would be subject to FERC approval.
In addition, the Utility’s customers may, under certain circumstances, obtain power from a “communitycommunity choice aggregator”aggregator (“CCA”) instead of from the Utility. California Assembly Bill 117, enacted in 2002,law permits cities and counties and certain other public agencies to purchase and sell electricity for their local residents and businesses onceafter they have registered as community choice aggregators.CCAs. Under Assembly Bill 117,these arrangements, the Utility would continuecontinues to provide distribution, metering, and billing services to the community choice aggregators' customers of the CCAs and would be those customers'remains the electricity provider of electricity of last resort. However, once registration has occurred, each community choice aggregator wouldresort for those customers. The law provides that a CCA can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The CPUC has adopted rules to implement community choice aggregation,the CCA program, including the imposition of a surcharge on retail end-users of the community choice aggregatorCCA to prevent a shifting of costs to customers of a utility who receive bundled services. Assembly Bill 117services and allowing a CCA to start service in phases. The law also authorizedauthorizes the Utility to recover from each community choice aggregatorCCA any costs of implementing the program that are reasonably attributable to the community choice aggregator,CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a community choice aggregator. NoCCA.
In some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or counties are currently operating as community choice aggregators, butstate statute to provide retail electric service, seek to acquire the Utility’s distribution facilities. For example South San Joaquin Valley Power AuthorityIrrigation District (“SSJID”) has filed an implementation planapplied to San Joaquin County Local Agency Formation Commission for the authority to provide electric distribution service in and statedaround the cities of Manteca, Ripon and Escalon. SSJID has indicated that, if it may begin operatingreceives the requested authority, it will seek to acquire the Utility’s distribution facilities, either under a consensual transaction, or via eminent domain.
It is also possible that technological developments could pose competitive challenges for traditional utilities. In particular, a combination of technology-related cost declines and sustained federal or state subsidies could make “distributed generation” a viable, cost-effective alternative to the Utility’s bundled electric service. The CPUC also has been considering the role of electric vehicles in 2009.California’s electricity infrastructure. In addition,July 2010, the CountyCPUC found that although the California Legislature did not intend that the CPUC regulate providers of Marinelectric vehicle charging services as public utilities, the CPUC has authority to regulate aspects of electric vehicle charging services. These aspects include rules relating to the deployment of electric vehicles; the terms under which a utility will provide services to electric vehicle charging providers; retail electricity rates paid by electric vehicle charging providers to a regulated utility; standards and several citiesprotocols to ensure functionality and interoperability between utilities and electric vehicle charging providers; and various electricity procurement requirements that apply to electricity service providers generally, such as resource adequacy and renewable energy procurement standards. A second phase of the CPUC proceeding will examine the role of the regulated utility in that county have votedelectric vehicle charging programs, ways to pursue community choice aggregationmanage the impact of such programs on the electric infrastructure, the cost to customers of such programs, and have formed a joint powers agency to do so, but have not yet filed an implementation plan.
FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from most of the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.
The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines. The CPUC divides
The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally,In addition, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential.
The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility'sUtility’s market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California, relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility'sUtility’s case, includes the cost of transportation of the natural gas from Canada and the U.S. Rocky Mountains to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California increases relative to other competing natural gas sources, the Utility'sUtility’s market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.
The Utility’s rates for electricity and natural gas utility services are based on its costs of providing service (“cost-of-service ratemaking”). Before setting rates, the CPUC and the FERC conduct proceedings to determine the annual amount of revenue (“revenue requirements”)requirements that the Utility is authorized to collect from its customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.
Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of
Regulatory balancing accounts are used to adjust the Utility’s revenue requirements. Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. In general, electricity sales are higher in the summer months and natural gas sales are higher in the winter months. Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes that can be affected by seasonal demand, weather, and other factors. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.
To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial, and agricultural) and to various service components (mainly customer, demand, and energy). Specific rate components are designed to produce the required revenue. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions. Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.
Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes some of the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.
While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as reliability standards or energy efficiency goals, instead of on the cost of providing service.
The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year. Typical interveners in the Utility'sUtility’s GRC include the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network.
On March 15, 2007,May 5, 2011, the CPUC approvedissued a multi-party settlement agreementfinal decision in the 2011 GRC to resolveauthorize the Utility’s 2007 GRC. The decision set the Utility’s electricityrevenue requirements for 2011 through 2013 for its costs to own and operate its electric and natural gas distribution and electricityelectric generation operations. The final decision approves the unopposed October 15, 2010 settlement agreement among the Utility, the DRA, TURN, and nearly all other intervening parties. The CPUC authorized a total 2011 revenue requirementsrequirement of approximately $6.0 billion, which reflects an overall increase of $450 million, or 8.0%, over
the total 2010 authorized amount of $5.6 billion, including $55 million for the recovery of financing costs and the accelerated return of capital associated with conventional meters that have been replaced by SmartMeterTM devices. As soon as July 2012, the Utility may file a four-year period, from 2007 through 2010, rather than for a typical three-year period. Undernotice of intent with the decision, the Utility’s next GRCCPUC that will be effective January 1, 2011. The Utility intends to submitinclude a draft of the 2011Utility’s GRC application and revenue requirement requestfor the period beginning January 1, 2014. The Utility plans to the CPUCfile its GRC application in July or August 2009. For more information, see the section of MD&A entitled “Results of Operations” in the 2008 Annual Report.
The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The CPUC’sCPUC decision in the Utility’s 20072011 GRC includes a provisionalso authorized attrition increases of $180 million for attrition adjustments made in 2008,2012 and to be made in 2009 and 2010. For more information, see the section of MD&A entitled “Results of Operations” in the 2008 Annual Report.
The CPUC generally conducts a proceeding to determineauthorizes the Utility's authorizedUtility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized raterates of return on each component that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The current authorized capital structure, consisting of 52% equity, 46% long-term debt, and 2% preferred stock, will remain in effect through 2012.
The CPUC has adopted a cost of capital proceeding establishes the relative weightings of common equity, preferred equity and debt in the Utility's total authorized capital structure. The CPUC then establishes the authorized return on each component that the Utility will collect in its authorized rates. In May 2008, the CPUC adopted a uniform three-year cost of capitaladjustment mechanism to set the cost of capital for the Utility and the other two California investor-owned electric utilities. The utilities are required to file full cost of capital applications by April 20 of every third year, beginning on April 20, 2010.
This mechanism did not trigger a change in the Utility’s authorized cost of debt, preferred stock, or equity for 2009.
The utilities may apply for an adjustment to either theUtility’s next full cost of capital or the capital structure sooner basedapplication must be filed by April 20, 2012, so that any resulting changes would become effective on extraordinary circumstances.
Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility'sUtility’s transmission rates are determined through a negotiated rate settlement.
Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility'sutility’s own generation facilities and existing electricity contracts (including DWR contracts allocated contracts)to the Utility’s customers). To accomplish this, each utility must submit a long-term procurement plan covering a ten-year10-year period to the CPUC for approval. Each long-term procurement plan must be designed to reduce greenhouse gasGHG emissions and use the State of California’s preferred loading order to meet forecasted demand (i.e.(i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation). In December 2007, the CPUC approved the utilities’ long-term procurement plans, covering the 2007-2016 period, subject to certain required modifications.
California legislation, Assembly Bill 57, allows the utilities to recover the costs
In December 2011, the CPUC approved the Utility’s bundled electricity procurement plan, covering 2011 through 2020, subject to certain required modifications. The Utility intends to file a revised bundled electricity procurement plan in April 2012 that is consistent with the CPUC’s December 2011 decision.
Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility'sutility’s prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.
On December 20, 2011, the CPUC approved the Utility’s forecast of 2012 procurement costs. The CPUC has not yet issued a decision to complete the Utility’s 2010 ERRA compliance review proceeding. The Utility will file its 2011 ERRA compliance review on February 15, 2012.
The CPUC has approved severalvarious power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.
For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to recover any above-market costs through either:either (1) the imposition of a non-bypassable charge imposed on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e.(i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’Utility’s service territory, including existing direct access customers and community choice aggregation customers.customers, under certain circumstances. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition in the Electricity Industry.”)
The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less. Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis. If a utility elects to useuses the net capacity cost allocation method, the net capacity costs would beare allocated for the term of the contract or 10 years, whichever is less, starting on the date the new generation unit comes on line. Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimizecontract. To use the net capacity costsallocation, the CPUC must determine that would be subjecta resource was needed to allocation. If no bids are acceptedmeet system or local area reliability needs for the benefit of all distribution customers. The CPUC can decide whether to require an energy rights, the Utility would retain the rightsauction for resources subject to the energy and would value it at market prices for the purposes of determining the net capacity cost allocation.
For renewable generation purchased from third parties under power purchase agreements, the Utility may recover any above-market costs to be allocated untilthrough the next periodic auction.
The CPUC-authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for operating Utility-owned generation facilities are addressed in the Utility’s GRC. The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which tracks the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for the Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year. For more information, see the section of MD&A entitled “Capital Expenditures – New Generation Facilities”Expenditures” in the 20082011 Annual Report.
The Utility may recover any above-market costs associated with new utility-owned generation resources through either (1) the imposition of a non-bypassable charge on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the Utility’s service territory, including existing direct access customers and community choice aggregation customers, under certain circumstances. The recovery of above-market costs is typically addressed in the CPUC order approving a specific utility-owned generation project.
During the 2000-2001 California 2000-2001 energy crisis, the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these
The Utility'sUtility’s electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: (1) charges under the Utility'sUtility’s transmission owner tariff and (2) charges under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the FERC in the Utility'sUtility’s transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility'sUtility’s retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.
The primary FERC rate-makingratemaking proceeding to determine the amount of revenue requirements that the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”). The Utility generally files a TO rate case every year, setting rates for a one-year period.year. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the
The Utility’s TO rate cases, see the section of MD&A entitled “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2008 Annual Report.
The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO. These revenues include:
The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge on the Utility for the Utility’s use of the CAISO-controlled electric transmission grid in serving its customers. The CAISO's transmission access charge methodology, approved by the FERC in December 2004, provides for a transition over a 10-year period, from 2000-2009, to a uniform statewide high-voltage transmission rate. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology may resultresults in a cost shift fromto transmission owners, whose costs for existing transmission facilities at 200 kV and above are higher than thatthose embedded in the uniform transmission access charge rate, tofrom transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligationcost shift amounts are recovered from the Utility’s retail customers as part of retail transmission rates.
Natural Gas Transmission and Storage Rate Cases
The CPUC determines the Utility’s authorized revenue requirements and rates for this cost differential has been capped at $32 million per year duringits natural gas transmission and storage services in a separate rate case called the 10-year transition period.
A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, will continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements will continuecontinues to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:
Backbone Transmission. The backbone transmission revenue requirement is recovered through a combination of firm two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available one-part rates (consisting only of volumetric usage charges). The mix of firm and as-available backbone services provided by the Utility continually changes. As a result, the Utility’s recovery of its backbone transmission costs is subject to volumetric and price risk to the extent that backbone capacity is sold on an as-available basis. Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity. Core customers are allocated approximately 36%38% of the total backbone capacity on the Utility’s system. Core customers pay approximately 72%69% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.
Local Transmission. The local transmission revenue requirement is allocated approximately 71%66% to core customers and 29%34% to non-core customers. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk.
Storage. The storage revenue requirement is allocated approximately 71%51% to core customers, 13%37% to non-core storage service, and 17%12% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk. The revenue requirement for pipeline load balancing service is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.
Certain of the Utility'sUtility’s natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.
The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.
The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. (The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered through electricity balancing accounts.)
The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism, the CPIM.Core Procurement Incentive Mechanism (“CPIM”). Under the CPIM, the Utility'sUtility’s purchase costs for a fixed twelve-month12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers'customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers'customers’ rates, and the Utility'sUtility’s customers receive in their rates 80% of any savings resulting from the Utility'sUtility’s cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped atremaining amount of savings are retained by the lower ofUtility as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs or $25 million.costs. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.
In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and The Utility also has received CPUC approvalReform Network to incorporate a portion of hedging costs for a long-term gas hedging program on behalf of core customers into the Utility’s CPIM beginning November 1, 2010. The settlement agreement has an initial term of seven years, through 2011. The costsOctober 2017, which can be extended by agreement of the parties. As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program are recovered directly from gas customers, outside the CPIM mechanism, and are subject only to a compliance review, not an after-the
The Utility'sUtility’s interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Utilities Commission and the National Energy Board. The Utility'sUtility’s agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility'sUtility’s core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky
Mountains, and the southwestern United States) to the points at which the Utility'sUtility’s natural gas transportation system begins. For more information, see the discussion below under “Natural Gas Utility Operations –— Interstate and Canadian Natural Gas Transportation Services Agreements.”
On February 24, 2011, the CPUC opened a rulemaking proceeding in order to develop and adopt safety-related changes to its regulation of natural gas transmission and distribution pipelines in California. The CPUC ordered each California natural gas transmission pipeline operator to submit a plan that describes the operator’s plan to either pressure test or replace those pipeline segments that have never been pressure tested or that lack sufficient detail related to the performance of a test. On August 26, 2011, the Utility filed its proposed plan and requested that the CPUC approve the proposed scope of the work to be done during the first phase (2011 through 2014) and authorize the Utility to recover estimated costs incurred after January 1, 2011. The Utility expects that it will incur significant costs to perform pipeline-related work within the proposed scope of the plan before the CPUC issues a decision and such costs may not be recoverable. Under the current procedural schedule, hearings will begin on March 12, 2012 and conclude on March 23, 2012 and a decision may not be issued until mid-2012 or later. For more information, see the section of MD&A entitled “Natural Gas Matters–CPUC Rulemaking Proceeding” in the 2011 Annual Report.
The following table showsUtility is required to maintain physical generating capacity adequate to meet its customers’ load, including peak demand and planning and operating reserves, deliverable to the percentage of the Utility's total sources of electricity for 2008 represented by each major electricity resource:
Total 2011 Actual Electricity Delivered – 74,864 GWh:
Percent of Bundled Retail Sales | ||||||||
Owned generation | ||||||||
Nuclear | 24.84% | |||||||
Small Hydroelectric | 1.67% | |||||||
Large Hydroelectric | 15.30% | |||||||
Fossil fuel-fired | 6.83% | |||||||
Solar | 0.03% | |||||||
Total | 48.67% | |||||||
DWR | ||||||||
Natural Gas | 3.57% | |||||||
Qualifying Facilities | ||||||||
Renewable | 5.32% | |||||||
Non-Renewable | 13.36% | |||||||
Total | 18.68% | |||||||
Irrigation Districts | ||||||||
Small Hydroelectric | 0.50% | |||||||
Large Hydroelectric | 5.74% | |||||||
Total | 6.24% | |||||||
Bilateral | ||||||||
Renewable | 11.81% | |||||||
Large Hydroelectric | 0.60% | |||||||
Non-Renewable | 8.48% | |||||||
Total | 20.89% | |||||||
Others, Net(1) | 1.95% | |||||||
Total | 100% | |||||||
(1) | This amount is mainly comprised of net CAISO open market purchases, offset by transmission and distribution related system losses. |
At December 31, 2008,2011, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:
Generation Type | County Location | Number of Units | Net Operating Capacity (MW) | |||
Nuclear: | ||||||
Diablo Canyon | San Luis Obispo | 2 | 2,240 | |||
Hydroelectric: | ||||||
Conventional | 16 counties in northern and central California | 107 | 2,684 | |||
Helms pumped storage | Fresno | 3 | 1,212 | |||
Hydroelectric subtotal | 110 | 3,896 | ||||
Fossil fuel: | ||||||
Humboldt Bay(1) | Humboldt | 2 | 105 | |||
Mobile turbines | Humboldt | 2 | 30 | |||
Fossil fuel subtotal | 4 | 135 | ||||
Total | 116 | 6,271 |
Generation Type | County Location | Number of Units | Net Operating Capacity (MW) | |||||||||
Nuclear: | ||||||||||||
Diablo Canyon | San Luis Obispo | 2 | 2,240 | |||||||||
Hydroelectric: | ||||||||||||
Conventional | 16 counties in northern and central California | 107 | 2,684 | |||||||||
Helms pumped storage(1) | Fresno | 3 | 1,212 | |||||||||
Hydroelectric subtotal: | 110 | 3,896 | ||||||||||
Fossil fuel-fired: | ||||||||||||
Colusa Generating Station | Colusa | 1 | 530 | |||||||||
Gateway Generating Station | Contra Costa | 1 | 530 | |||||||||
Humboldt Bay Generating Station | Humboldt | 10 | 163 | |||||||||
CSU East Bay Fuel Cell | Alameda | 1 | 1.4 | |||||||||
SF State Fuel Cell | San Francisco | 2 | 1.6 | |||||||||
Fossil fuel-fired subtotal: | 15 | 1,226 | ||||||||||
Photovoltaic: | ||||||||||||
Five Points Solar Station | Fresno | 1 | 15 | |||||||||
Stroud Solar Station | Fresno | 1 | 20 | |||||||||
Westside Solar Station | Fresno | 1 | 15 | |||||||||
Vaca Dixon Solar Station | Solano | 1 | 2 | |||||||||
Small Solar Stations | San Francisco | 3 | 0.3 | |||||||||
Photovoltaic subtotal | 7 | 52 | ||||||||||
Total | 134 | 7,414 | ||||||||||
|
|
(1) | See the discussion below about the status of outages of these units. |
Diablo Canyon Power Plant. The Utility'sUtility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. Unit 1 began commercial operation in May 1985, and the operating license for this unit expires in November 2024. Unit 2 began commercial operation in March 1986, and the operating license for this unit expires in August 2025. For the 10-yeartwelve months period ended December 31, 2008,2011, the Utility'sUtility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 89.9%95%. The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025. In November 2009, the Utility filed an application at the NRC requesting that each of these licenses be renewed for 20 years. For more information on the renewal process and other matters affecting Diablo Canyon, see the section of MD&A entitled “Regulatory Matters-Diablo Canyon Nuclear Power Plant” in the 2011 Annual Report.
The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 17:15: Commitments and Contingencies—Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 20082011 Annual Report.
The following table outlines the Diablo Canyon power plant'splant’s refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 51 days. The Utility will replace the steam generators in Unit 1 during the scheduled refueling outage that began in January 2009. Due to this additional work, this refueling outage is expected to last approximately 7644.6 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.
2009 | 2010 | 2011 | 2012 | 2013 | |||||
Unit 1 | |||||||||
Refueling | January | October | April | ||||||
Duration (days) | 76 | 35 | 30 | ||||||
Startup | April | November | May | ||||||
Unit 2 | |||||||||
Refueling | October | - | May | February | |||||
Duration (days) | 35 | - | 30 | 30 | |||||
Startup | November | - | June | March |
2012 | 2013 | 2014 | 2015 | 2016 | ||||||||
Unit 1 | ||||||||||||
Refueling | April | - | February | September | - | |||||||
Duration (days) | 45 | - | 35 | 35 | - | |||||||
Startup | June | - | March | October | - | |||||||
Unit 2 | ||||||||||||
Refueling | - | February | September | - | May | |||||||
Duration (days) | - | 45 | 35 | - | 30 | |||||||
Startup | - | March | October | - | May |
Hydroelectric Generation Facilities. The Utility'sUtility’s hydroelectric system consists of 110 generating units at 6968 powerhouses, including athe Helms pumped storage facility, with a total generating capacity of 3,896 MW. Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their unit capacity exceeds 30 MW. The system includes 99 reservoirs, 56 diversions, 170174 dams, 184172 miles of canals, 4443 miles of flumes, 135130 miles of tunnels, 1954 miles of pipe (penstocks, siphons and low head pipes), and 5 miles of natural waterways. The system also includes water rights as specified in 9089 permits or licenses and 160159 statements of water diversion and use.
The Helms pumped storage facility consists of three motor/generator units with a combined capacity of 1,212 MW. During 2011, the Utility began inspections of all three units following reports of a significant failure of a similarly designed pumped storage generation unit in Austria that was apparently caused by cracks in the generator rotor poles due to metal fatigue. Inspection of this area of the generation unit requires a significant outage while the generator rotor is disassembled and re-assembled after any necessary inspections and repairs are made. The Utility inspected Unit 2 during a planned outage in September 2011 and found cracks that have since been repaired and the Utility has returned Unit 2 to full operation. The Utility removed Unit 3 from service for inspection in October 2011. The Utility found cracks in the generator rotor of Unit 3 which are being repaired so that the unit can be returned to full service. On November 19, 2011, an unrelated equipment failure occurred on Unit 1 which damaged the generator and Unit 1 was removed from service. Depending on the effectiveness of repairs being implemented, the Utility expects that Unit 1 will become operational by the end of 2012.
All of the Utility'sUtility’s powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years. In the last fivethree years, the FERC renewed threetwo hydroelectric licenses associated with a total capacity of 415 MW of hydroelectric power.110 MW. The Utility is in the process of renewing hydroelectric licenses for projectsassociated with capacity of approximately 1,1831,072 MW and surrendering the hydroelectric license associated with the Kilarc-Cow Creek Project which has a capacity of additional hydroelectric power.5 MW. Although the original licenses associated with 599880 MW of the 1,1831,072 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 2,7013,003 MW of hydroelectric power will expire between 20182013 and 2043.
NewConventional Generation Facilities.In addition to the Utility-owned resources shown in the table above, the Utility has been engaged in the development of three The Utility’s conventional generation facilities to be owned and operated by the Utility. On January 4, 2009, the 530-MW Gateway Generating Station located in Antioch, California, reached full load commercial production and is expected to reach final project completion at the end of the first quarter of 2009. In June 2008, the CPUC approved the construction ofinclude the Colusa Generating Station, a 657- MW combined cycle generating facility with 530 MW of base capacity and 127 MW of enhanced capability that became operational in December 2010, the Gateway Generating Station with 530 MW of base capacity and 50 MW of enhanced capability that became operational in January 2009, and the 163-MW Humboldt Bay generating station that became operational in September 2010. In addition, the Utility owns and operates three fuel cell sites in the Bay Area that became operational in September 2011 and have a combined capacity of 3 MW.
In December 2010, the CPUC approved a purchase and sale agreement between the Utility and Contra Costa Generating Station LLC for the development and construction of the Oakley Generation Facility, a 586-MW natural gas-fired, combined-cycle generation facility proposed to be located in Colusa County,Oakley, California. Final environmental permitting was approved on September 29, 2008 and construction began on October 1, 2008. Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations in 2010. Also, in September 2008, the CEC issued its final decision authorizing the construction of a 163-MW power plant to re-power the Utility’s existing power plant at Humboldt Bay, which is at the end of its useful life. Demolition of existing structures on the site is complete and the contractor began preparing the site for construction in December 2008. Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in 2010. For more information about the status of this proposed facility, see the section of MD&A entitled “Capital Expenditures ─ New
Photovoltaic Facilities.In April 2010, the CPUC approved the Utility’s proposed five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties. During 2011, Utility-owned PV facilities with an aggregate capacity of 50 MW became operational. These facilities include the Five Points Solar Station, the Stroud Solar Station, and the Westside Solar Station, each of which is located in Fresno County. Three other PV facilities with an aggregate capacity of 50 MW are currently under construction. They are estimated to become operational by October 2012.
During 2008,2011, electricity from the DWR contracts allocated to the Utility provided approximately 15%3.57% of the electricity delivered to the Utility'sUtility’s customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as thethese contracts expire or terminate. For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies – California Department of Water Resources Contracts, of the Notesare novated to the Consolidated Financial Statements in the 2008 Annual Report.
Qualifying FacilityQF Power Purchase Agreements.As of December 31, 2008,2011, the Utility had power purchase agreements with 246217 QFs for approximately 3,9003,400 MW of capacity that are in operation. Approximately 2,200 MW of this capacity is from cogeneration projects and 1,200 MW is from renewable generation resources, as discussed below. Agreements for approximately 3,6003,100 MW expire at various dates between 20092012 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 74 inoperative QFs. The total of approximately 3,900 MW consists of roughly 2,500 MW from cogeneration projects, 600 MW from wind projects and 800 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. QF power purchase agreementspurchases accounted for approximately 18%, 20%, and 20%,18.68% of the Utility’s 2008, 2007, and 20062011 electricity sources, respectively.deliveries. No single QF accounted for more than 5% of the Utility's 2008, 2007, or 2006Utility’s 2011 electricity sources.deliveries.
In December 2010, the CPUC approved a settlement agreement among the California investor-owned utilities, ratepayer groups, and representatives of the facilities that produce combined heat and power (“CHP”), including CHP facilities that also qualify as QFs. The settlement establishes a new CHP/QF Program that sets CHP procurement targets and GHG reduction targets (consistent with AB 32), provides for a transition of existing QF energy pricing to market-based pricing by 2015, and implements new standard power purchase agreements. In accordance with the settlement agreement, the utilities filed a joint application with the FERC requesting the FERC to terminate the utilities’ obligations under PURPA to purchase power from all QFs sized 20 MW and above. The FERC approved the joint application in June 2011. The settlement agreement became effective on November 23, 2011 when all of the conditions precedent were satisfied.
Irrigation Districts and Water Agencies.The Utility also has contractsentered into agreements with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts,power that require the Utility mustto make specified semi-annual fixed minimum payments. In addition, these agreements require the Utility to make variable payments based on the irrigation districts' and water agencies' debt service requirements, whether or not any hydroelectric power is supplied, and variable payments for operationoperating and maintenance costs incurred by the suppliers.irrigation districts and water agencies. These contracts will expire on various dates from 2010 tobetween 2012 and 2031. The Utility's irrigation district and water agency contractsIn 2011, they accounted for approximately 2%, 3%, and 6%6.24% of the Utility’s electricity sources in 2008, 2007, and 2006, respectively.deliveries.
Renewable EnergyBilateral Contracts. California law requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity delivered from renewable resources equals at least 20% of its total retail sales by the end of 2010. During 2008, the Utility entered into new renewable power purchase contracts that will help the Utility meet this RPS by 2010.
For more information regarding the Utility'sUtility’s power purchase contracts, see Note 17:15: Commitments and Contingencies—Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 20082011 Annual Report.
Future Long-TermRenewable Generation Resources
Renewable generation resources include biomass, small hydroelectric, wind, solar, and geothermal energy. In April 2011, the California Governor signed legislation that establishes a new RPS that requires load-serving entities, such as the Utility, to increase the amount of renewable energy they procure from at least 20% of their total retail sales, as required by the prior RPS law, to 33% of their total retail sales. The Utility’s CPUC-approved long-term electricityRPS law establishes three initial compliance periods: 2011-2013, 2014-2016, and 2017-2020. The RPS compliance requirement that must be met for each of these compliance periods will gradually increase. Thereafter, compliance with the 33% RPS requirement will be determined on an annual basis.
The new RPS law creates three distinct categories (or “buckets”) of renewable energy products that can be used to meet the RPS requirements and imposes minimum or maximum procurement plan, coveringtargets for each of these product categories for each compliance period. With certain exceptions, these categorical requirements will only apply to renewable energy contracts entered into after June 1, 2010. The new law also (1) limits the use of certain types of unbundled renewable energy credits and (2) restricts the ability to carry forward (or “bank”) RPS volumes from certain types of short-term contracts, to satisfy compliance obligations.
On December 15, 2011, the CPUC issued a decision to adopt the criteria for each “portfolio content category.” The decision requires all retail sellers to provide sufficient information about their RPS procurement during 2007-2016, forecastsso the CPUC can make a compliance determination that the Utilityretail seller’s RPS procurement actually meets the requirements of the portfolio content category which the retail seller claims. In addition, investor-owned utilities must provide specific information when seeking CPUC approval of RPS procurement contracts that will needallow the CPUC to obtainevaluate the proposed portfolio content category of the planned procurement, and the value and risk of the planned procurement to the utilities’ ratepayers.
In addition, the CPUC is expected to determine whether to change the penalty provisions established under the former RPS law, which provided for a maximum penalty of $25 million per year on each load-serving entity that had an additional 800unexcused failure to 1,200 MW ofmeet its compliance obligation. Until the CPUC adopts regulations to implement the new conventional generation by 2015 abovelaw, it is uncertain how the Utility's planned additionsCPUC’s regulations and decisions issued pursuant to the former RPS statute, including the penalty provisions, will apply to the new RPS requirements.
Additionally, the CEC, which continues to have responsibility for certifying the eligibility of renewable resources and verifying LSE compliance with the RPS program, has also initiated a proceeding to implement the new RPS law and is expected to issue one or more draft regulations in the second quarter of 2012.
The costs incurred by the Utility under third-party contracts to meet RPS requirements are tracked in a balancing account and recovered through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximums authorized by the CPUC for the respective project.
For the year ended December 31, 2011, the Utility’s RPS-eligible renewable resource deliveries equaled 19.3% of its total retail electricity sales. Most renewable energy efficiency, demand reduction programs,deliveries resulted from third party contracts, mainly QF agreements and previously approvedbilateral contracts. Additional renewable resources included the Utility’s small hydroelectric and solar facilities and certain irrigation district contracts for new generation resources.
Total 2011 renewable deliveries are stated in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to take advantage of a unique and fleeting
Type | GWh | % of Bundled | ||
Biopower | 3,319 | 4.4% | ||
Geothermal | 3,781 | 5.0% | ||
Wind | 4,428 | 5.9% | ||
Small Hydroelectric | 2,733 | 3.7% | ||
Solar | 210 | 0.3% | ||
|
| |||
Total | 14,471 | 19.3% | ||
|
|
For more information regarding the Utility's proposal,Utility’s renewable energy contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the section of MD&A entitled “Capital Expenditures ─ Proposed New Generation Facilities”Notes to the Consolidated Financial Statements in the 20082011 Annual Report.
At December 31, 2008,2011, the Utility owned 18,650approximately 18,618 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 56,401approximately 59,743 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 141,036approximately 141,000 circuit miles of distribution lines and substations with a capacity of 27,13729,066 MVA. In 2008,2011, the Utility delivered 88,12774,684 GWh to its customers; including 6,191customers, and approximately 8,494 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.
During 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO. The Utility is required to give the CAISO two years notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.
The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following the EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under “The Utility’s Regulatory Environment-FederalEnvironment — Federal Energy Regulation.”
The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO'sCAISO’s demand when the generation from those RMR units is needed for local transmission system reliability.) Potential transmission projects include a 500-kV transmission line to improve access to new renewable generation resources and to reduce RMR generation contracts in the Fresno, California area (referred to as the “Central California Clean Energy Transmission Project”) and a high voltage transmission line between Northern California and British Columbia, Canada to access renewable generation resources in British Columbia. In addition, the Utility is currently working with several stakeholders in the western United States to assess the feasibility of new large-scale electric transmission expansion projects to address regional electricity needs over the long term.
The Utility'sUtility’s electricity distribution network extends through 47 of California'sCalifornia’s 58 counties, comprising most of northern and central California. The Utility'sUtility’s network consists of 141,036approximately 141,000 circuit miles of distribution lines (of which approximately 19%20% are underground and approximately 81%80% are overhead). There are 9291 transmission substations and 4857 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 607 distribution substations and 110 low-voltage601 distribution substations. The 4957 combined transmission and distribution substations have both transmission and distribution transformers.
The Utility'sUtility’s distribution network interconnects to the Utility'sUtility’s electricity transmission system at 1,106approximately 1,758 points. This interconnection between the Utility'sUtility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility'sUtility’s customers. The distribution substations serve as the central hubs of the Utility'sUtility’s electricity distribution network and consist of transformers, voltage regulation equipment, protective devices, and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.
Much of the Utility’s electric transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s population and economy grew. The Utility beganmakes capital investments in its electric transmission and distribution infrastructure to extend the installationlife of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.
The Utility has been installing an advanced metering infrastructure known asusing SmartMeterTM technology throughout its service territory. As of December 31, 2011, the SmartMeter™ program, for virtually all of the Utility'sUtility has installed approximately 8.9 million advanced electric and gas customers. These meters enable the Utility to measurethrough its service territory. Advanced electric meters, which record energy usage on anin hourly basis for electricity and on a daily basis for natural gas, which canor quarter-hourly increments, allow for demand-response rates to encourage customers to reducetrack energy consumption during peak demand periods,usage throughout the billing month and thus reducing peak period procurementenable greater customer control over electricity costs. Advanced meters can record usage in time intervalsUsage data is collected through a wireless communication network and be read remotely. Thetransmitted to the Utility’s information system where the data is stored and used for billing and other Utility expectsbusiness purposes.
Following customer complaints that the new metering system led to completeovercharges, the CPUC began an investigation and several municipalities took various steps to delay or suspend the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011. The Utility also has requestednew meters. On February 1, 2012, the CPUC issued a decision that permits customers to approve the Utility’s proposal to upgrade elementsopt out of the Utility’s SmartMeter™ SmartMeterTMprogram. The Utility seeks approval to install solid-state electric meters and associated devices that would offer an expanded range of service features for customers and increased operational efficiencies for the Utility. These upgraded meters and associated devices would provide additional energy conservation and demand response options for electric customers. In addition, the solid-state electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner. (For moreFor information about the advanced metering infrastructure,these matters, see the section of MD&A entitled “Capital Expenditures ─ SmartMeter™ Program”“Regulatory Matters – Deployment of SmartMeterTM Technology” in the 20082011 Annual Report.)
The following table shows the percentage of the Utility'sUtility’s total 20082011 electricity deliveries represented by each of its major customer classes:
Total 20082011 Electricity Delivered: 88,12783,688 GWh
Residential Customers | 37% | |||
Commercial Customers | 39% | |||
Industrial Customers | 17% | |||
Agricultural and Other Customers | 7% | |||
Total | 100% | |||
The following table shows certain of the Utility'sUtility’s operating statistics from 20042007 to 20082011 for electricity sold or delivered, including the classification of sales and revenues by type of service.
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
Customers (average for the year): | ||||||||||||||||||||
Residential | 4,488,884 | 4,464,483 | 4,417,638 | 4,353,458 | 4,366,897 | |||||||||||||||
Commercial | 527,045 | 521,732 | 515,297 | 509,786 | 509,501 | |||||||||||||||
Industrial | 1,265 | 1,261 | 1,212 | 1,271 | 1,339 | |||||||||||||||
Agricultural | 81,757 | 80,366 | 79,006 | 78,876 | 80,276 | |||||||||||||||
Public street and highway lighting | 30,474 | 29,643 | 28,799 | 28,021 | 27,176 | |||||||||||||||
Other electric utilities | 2 | 2 | 4 | 4 | 3 | |||||||||||||||
Total (1) | 5,129,427 | 5,097,487 | 5,041,956 | 4,971,416 | 4,985,192 | |||||||||||||||
Deliveries (in GWh):(2) | ||||||||||||||||||||
Residential | 31,454 | 30,796 | 31,014 | 29,752 | 29,453 | |||||||||||||||
Commercial | 34,053 | 33,986 | 33,492 | 32,375 | 32,268 | |||||||||||||||
Industrial | 16,148 | 15,159 | 15,166 | 14,932 | 14,796 | |||||||||||||||
Agricultural | 5,594 | 5,402 | 3,839 | 3,742 | 4,300 | |||||||||||||||
Public street and highway lighting | 877 | 833 | 785 | 792 | 2,091 | |||||||||||||||
Other electric utilities | 1 | 3 | 14 | 33 | 28 | |||||||||||||||
Subtotal | 88,127 | 86,179 | 84,310 | 81,626 | 82,936 | |||||||||||||||
California Department of Water Resources (DWR) | (13,344 | ) | (21,193 | ) | (19,585 | ) | (20,476 | ) | (19,938 | ) | ||||||||||
Total non-DWR electricity | 74,783 | 64,986 | 64,725 | 61,150 | 62,998 | |||||||||||||||
Revenues (in millions): | ||||||||||||||||||||
Residential | $ | 4,656 | $ | 4,580 | $ | 4,491 | $ | 3,856 | $ | 3,718 | ||||||||||
Commercial | 4,413 | 4,484 | 4,414 | 4,114 | 4,179 | |||||||||||||||
Industrial | 1,400 | 1,252 | 1,293 | 1,232 | 1,204 | |||||||||||||||
Agricultural | 727 | 664 | 483 | 446 | 491 | |||||||||||||||
Public street and highway lighting | 75 | 78 | 72 | 66 | 71 | |||||||||||||||
Other electric utilities | 126 | 85 | 59 | 4 | 22 | |||||||||||||||
Subtotal | 11,397 | 11,143 | 10,812 | 9,718 | 9,685 | |||||||||||||||
DWR | (1,325 | ) | (2,229 | ) | (2,119 | ) | (1,699 | ) | (1,933 | ) | ||||||||||
Direct access credits | — | — | — | — | — | |||||||||||||||
Miscellaneous | 336 | 215 | 261 | 235 | (248 | ) | ||||||||||||||
Regulatory balancing accounts | 330 | 352 | (202 | ) | (327 | ) | 363 | |||||||||||||
Total electricity operating revenues | $ | 10,738 | $ | 9,481 | $ | 8,752 | $ | 7,927 | $ | 7,867 | ||||||||||
Other Data: | ||||||||||||||||||||
Average annual residential usage (kWh) | 7,007 | 6,898 | 7,020 | 6,834 | 6,744 | |||||||||||||||
Average billed revenues (cents per kWh): | ||||||||||||||||||||
Residential | 14.80 | 14.87 | 14.48 | 12.96 | 12.62 | |||||||||||||||
Commercial | 12.96 | 13.19 | 13.18 | 12.71 | 12.95 | |||||||||||||||
Industrial | 8.67 | 8.26 | 8.53 | 8.25 | 8.14 | |||||||||||||||
Agricultural | 13.00 | 12.29 | 12.58 | 11.92 | 11.41 | |||||||||||||||
Net plant investment per customer | $ | 3,994 | $ | 3,418 | $ | 3,148 | $ | 2,966 | $ | 2,790 |
2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
Customers (average for the year): | ||||||||||||||||||||
Residential | 4,540,315 | 4,509,620 | 4,492,359 | 4,488,884 | 4,464,483 | |||||||||||||||
Commercial | 530,914 | 529,318 | 528,786 | 527,045 | 521,732 | |||||||||||||||
Industrial | 1,261 | 1,254 | 1,285 | 1,265 | 1,261 | |||||||||||||||
Agricultural | 83,823 | 83,787 | 83,581 | 81,757 | 80,366 | |||||||||||||||
Public street and highway lighting | 32,323 | 31,743 | 31,227 | 30,474 | 29,643 | |||||||||||||||
Other electric utilities | 2 | 2 | 2 | 2 | 2 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | 5,188,638 | 5,155,724 | 5,137,240 | 5,129,427 | 5,097,487 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Deliveries (in GWh):(1) | ||||||||||||||||||||
Residential | 30,871 | 30,744 | 31,234 | 31,454 | 30,796 | |||||||||||||||
Commercial | 32,842 | 32,863 | 32,958 | 34,053 | 33,986 | |||||||||||||||
Industrial | 14,498 | 14,415 | 14,806 | 16,148 | 15,159 | |||||||||||||||
Agricultural | 4,692 | 5,071 | 5,804 | 5,594 | 5,402 | |||||||||||||||
Public street and highway lighting | 781 | 815 | 826 | 877 | 833 | |||||||||||||||
Other electric utilities | 4 | - | 1 | 1 | 3 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Subtotal | 83,688 | 83,908 | 85,629 | 88,127 | 86,179 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
California Department of Water Resources (DWR) | (2,433) | (4,274) | (13,244) | (13,344) | (21,193) | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total non-DWR electricity | 81,255 | 79,634 | 72,385 | 74,783 | 64,986 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Revenues (in millions): | ||||||||||||||||||||
Residential | $ 4,778 | $ 4,795 | $ 4,759 | $ 4,656 | $ 4,580 | |||||||||||||||
Commercial | 4,732 | 4,823 | 4,538 | 4,413 | 4,484 | |||||||||||||||
Industrial | 1,379 | 1,424 | 1,392 | 1,400 | 1,252 | |||||||||||||||
Agricultural | 692 | 736 | 770 | 727 | 664 | |||||||||||||||
Public street and highway lighting | 77 | 79 | 74 | 75 | 78 | |||||||||||||||
Other electric utilities | 64 | 60 | 66 | 126 | 85 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Subtotal | 11,722 | 11,917 | 11,599 | 11,397 | 11,143 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
DWR | - | (1,383) | (1,987) | (1,325) | (2,229) | |||||||||||||||
Miscellaneous | 30 | 145 | 221 | 336 | 215 | |||||||||||||||
Regulatory balancing accounts | (151) | (35) | 424 | 330 | 352 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total electricity operating revenues | $ 11,601 | $ 10,644 | $ 10,257 | $ 10,738 | $ 9,481 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Other Data: | ||||||||||||||||||||
Average annual residential usage (kWh) | 6,799 | 6,843 | 6,953 | 7,007 | 6,898 | |||||||||||||||
Average billed revenues (cents per kWh): | ||||||||||||||||||||
Residential | $ 15.48 | $ 15.60 | $ 15.24 | $ 14.80 | $ 14.87 | |||||||||||||||
Commercial | 14.41 | 14.68 | 13.77 | 12.96 | 13.19 | |||||||||||||||
Industrial | 9.51 | 9.88 | 9.40 | 8.67 | 8.26 | |||||||||||||||
Agricultural | 14.75 | 14.51 | 13.27 | 13.00 | 12.29 | |||||||||||||||
Net plant investment per customer | $ 5,045 | $ 4,728 | $ 4,336 | $ 3,994 | $ 3,418 |
These amounts include electricity provided to direct access customers who procure their own supplies of electricity. |
The Utility owns and operates an integrated natural gas transportation, storage, and distribution system in California that extends throughout all or a part of 40 of California'sCalifornia’s 58 counties and includes most of northern and central California. In 2008,2011, the Utility served approximately 4.34 million natural gas distribution customers.
The total volume ofCPUC divides the Utility’s on-system natural gas throughput during 2008 was approximately 839 Bcf.
The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. Currently, over 3% of core customers, representing over 15% of the annual core market demand, receive bundled natural gas service from the Utility.
The Utility does not provide procurement service to electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers. However, some non-core customers are eligible to elect to receive core service, including procurement service, if such customers contract to receive core service for at least five years. These restrictions were put in place because large increases in demand for the Utility’s procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.
The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility’s backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.
The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not affected by weather variations, conservation, or changes in their consumption levels. The Utility’s results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility’s natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.
As of December 31, 2008,2011, the Utility'sUtility’s natural gas system consisted of 42,017approximately 42,309 miles of distribution pipelines, 6,418approximately 6,431 miles of backbone and local transmission pipelines, and threevarious storage facilities. The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems. The Utility'sUtility’s Line 300, which interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned by third parties (Transwestern Pipeline Co.,Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company), has a receipt capacity of approximately 1.07 Bcf per day. The Utility'sUtility’s Line 400/401 interconnects with the natural gas transportation pipeline of TransCanada’s Gas Transmission Northwest CorporationLLC (“GTN”) and Ruby Pipeline, LLC (“Ruby Pipeline”) at the California-Oregon border. This line has acombined receipt capacity at the border ofis approximately 2.022.0 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States. The Utility also is supplied by natural gas fields in California.
The Utility also owns and operates three underground natural gas storage fields connectedand has a 25% interest in the Gill Ranch underground natural gas storage facility located near Fresno, California. These facilities currently provide the Utility with approximately 106.5 bcf of maximum working gas capacity. When the Gill Ranch storage facility is fully developed, the Utility’s total maximum working gas capacity would increase to the Utility's transmission and storage system. These storage fields have a combined firm capacity of approximately 47 Bcf.107.2 bcf. In addition, twothree independent storage operators are interconnected to the Utility'sUtility’s northern California transportation system.
During 2011, the Utility took significant action to implement the recommendations made by the NTSB and the CPUC’s independent review panel to improve the Utility’s natural gas operating practices and procedures and to comply with CPUC orders. Among other tasks, the Utility has validated the maximum allowable operating pressure (“MAOP”) of approximately 1,800 miles of pipelines, automated 11 shut off- valves, and conducted hydrostatic pressure tests on approximately 165 miles of pipelines. The Utility along with Gill Ranch Storage, LLC, a subsidiaryalso is taking steps to improve its emergency response procedures and training, its supervisory controls and data acquisition system and procedures to better detect pipeline leaks and breaks, its integrity management program (including new analysis tools to identify and assess risks to pipeline integrity), its pipeline safety measures and public awareness of Northwestpipeline safety measures, and its data management system which is intended to address the NTSB’s and the CPUC’s recommendations for traceable, verifiable and complete records.
2011 Natural Gas Company, is developing an undergroundDeliveries
The total volume of natural gas storage facility near Fresno, California. It is expected that constructiondelivered to on-system customers during 2011 was approximately 804 MMDth. The following table shows the percentage of the initial phase, to consist of approximately 20 Bcf ofUtility’s total capacity, will be completed in 2010. The Utility has a 25% interest in the initial phase2011 natural gas deliveries represented by each of the proposed storage facility. Development of the storage facility is subject to CPUC approval, including the CPUC’s environmental review as required by the California Environmental Quality Act. The Utility expects the CPUC to issue a final decision in late 2009.
Total 2011 Natural Gas Deliveries: 804 Bcf
Residential Customers | 30 | % | ||
Transport-only Customers (non-core) | 57 | % | ||
Commercial Customers | 13 | % |
The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 20082011 California Gas Report forecasts average annual growth in the Utility'sUtility’s natural gas deliveries (for core customers and non-core transportation) of approximately 0.2%0.3% for the years 20082011 through 2030. The natural gas requirements forecast is subject to many uncertainties, and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.
2008 Natural Gas Deliveries. Operating Statistics
The following table shows the percentage of the Utility's total 2008 natural gas deliveries represented by each of the Utility's major customer classes:
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
Customers (average for the year): | ||||||||||||||||||||
Residential | 4,043,616 | 4,030,499 | 3,989,331 | 3,929,117 | 3,812,914 | |||||||||||||||
Commercial | 224,617 | 223,330 | 220,024 | 216,749 | 215,547 | |||||||||||||||
Industrial | 926 | 958 | 988 | 962 | 2,178 | |||||||||||||||
Other gas utilities | 6 | 6 | 6 | 6 | 6 | |||||||||||||||
Total | 4,269,165 | 4,254,793 | 4,210,349 | 4,146,834 | 4,030,645 | |||||||||||||||
Gas supply (MMcf): | ||||||||||||||||||||
Purchased from suppliers in: | ||||||||||||||||||||
Canada | 189,608 | 199,870 | 202,274 | 204,884 | 205,180 | |||||||||||||||
California | (53,126 | ) | (23,065 | ) | (13,401 | ) | (18,951 | ) | (9,108 | ) | ||||||||||
Other states | 123,833 | 101,271 | 103,658 | 103,237 | 103,801 | |||||||||||||||
Total purchased | 260,315 | 278,076 | 292,531 | 289,170 | 299,873 | |||||||||||||||
Net (to storage) from storage | 560 | (1,120 | ) | 4,359 | (3,659 | ) | (532 | ) | ||||||||||||
Total | 260,875 | 276,956 | 296,890 | 285,511 | 299,341 | |||||||||||||||
Utility use, losses, etc. (1) | 1,758 | (12,760 | ) | (27,610 | ) | (14,312 | ) | (19,287 | ) | |||||||||||
Net gas for sales | 262,633 | 264,196 | 269,280 | 271,199 | 280,054 | |||||||||||||||
Bundled gas sales (MMcf): | ||||||||||||||||||||
Residential | 198,699 | 196,903 | 196,092 | 194,108 | 201,601 | |||||||||||||||
Commercial | 63,934 | 67,293 | 73,178 | 77,056 | 78,080 | |||||||||||||||
Industrial | 10 | 35 | 373 | |||||||||||||||||
Other gas utilities | — | — | — | — | — | |||||||||||||||
Total | 262,633 | 264,196 | 269,280 | 271,199 | 280,054 | |||||||||||||||
Transportation only (MMcf): | 569,535 | 605,259 | 559,270 | 572,869 | 597,706 | |||||||||||||||
Revenues (in millions): | ||||||||||||||||||||
Bundled gas sales: | ||||||||||||||||||||
Residential | $ | 2,574 | $ | 2,378 | $ | 2,452 | $ | 2,336 | $ | 1,944 | ||||||||||
Commercial | 792 | 766 | 859 | 885 | 712 | |||||||||||||||
Industrial | ||||||||||||||||||||
Other gas utilities | ||||||||||||||||||||
Miscellaneous | (30 | ) | 87 | 121 | (22 | ) | (29 | ) | ||||||||||||
Regulatory balancing accounts | 221 | 186 | 40 | 340 | 316 | |||||||||||||||
Bundled gas revenues | 3,557 | 3,417 | 3,472 | 3,539 | 2,943 | |||||||||||||||
Transportation service only revenue | 333 | 340 | 315 | 237 | 270 | |||||||||||||||
Operating revenues | $ | 3,890 | $ | 3,757 | $ | 3,787 | $ | 3,776 | $ | 3,213 | ||||||||||
Selected Statistics: | ||||||||||||||||||||
Average annual residential usage (Mcf) | 49 | 49 | 49 | 49 | 53 | |||||||||||||||
Average billed bundled gas sales revenues per Mcf: | ||||||||||||||||||||
Residential | $ | 12.95 | $ | 12.07 | $ | 12.50 | $ | 12.04 | $ | 9.64 | ||||||||||
Commercial | 12.38 | 11.38 | 11.73 | 11.48 | 9.12 | |||||||||||||||
Industrial | 1.03 | 0.61 | (0.56 | ) | ||||||||||||||||
Average billed transportation only revenue per Mcf | 0.59 | 0.56 | 0.56 | 0.42 | 0.45 | |||||||||||||||
Net plant investment per customer | $ | 1,344 | $ | 1,375 | $ | 1,304 | $ | 1,262 | $ | 1,266 | ||||||||||
2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
Customers (average for the year): | ||||||||||||||||||||
Residential | 4,100,712 | 4,070,420 | 4,046,364 | 4,043,616 | 4,030,499 | |||||||||||||||
Commercial | 225,769 | 224,400 | 223,709 | 224,617 | 223,330 | |||||||||||||||
Industrial | 920 | 915 | 928 | 926 | 958 | |||||||||||||||
Other gas utilities | 6 | 6 | 6 | 6 | 6 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | 4,327,407 | 4,295,741 | 4,271,007 | 4,269,165 | 4,254,793 | |||||||||||||||
|
|
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|
|
|
|
|
|
| |||||||||||
Gas supply (MMcf): | ||||||||||||||||||||
Purchased from suppliers in: | �� | |||||||||||||||||||
Canada | 197,151 | 206,800 | 190,485 | 189,608 | 199,870 | |||||||||||||||
California(1) | (23,988) | (32,910) | (41,714) | (53,126) | (23,065) | |||||||||||||||
Other states | 105,994 | 96,338 | 115,543 | 123,833 | 101,271 | |||||||||||||||
|
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|
|
|
|
|
|
|
| |||||||||||
Total purchased | 279,157 | 270,228 | 264,314 | 260,315 | 278,076 | |||||||||||||||
Net (to storage) from storage | (709) | (314) | 876 | 560 | (1,120) | |||||||||||||||
|
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|
|
|
|
|
|
|
| |||||||||||
Total | 278,448 | 269,914 | 265,190 | 260,875 | 276,956 | |||||||||||||||
Utility use, losses, etc.(2) | (25,109) | (20,798) | (12,423) | 1,758 | (12,760) | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Net gas for sales | 253,339 | 249,116 | 252,767 | 262,633 | 264,196 | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Bundled gas sales (MMcf): | ||||||||||||||||||||
Residential | 201,109 | 195,195 | 195,217 | 198,699 | 196,903 | |||||||||||||||
Commercial | 52,230 | 53,921 | 57,550 | 63,934 | 67,293 | |||||||||||||||
Industrial | — | — | — | — | — | |||||||||||||||
Other gas utilities | — | — | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
| |||||||||||
Total | 253,339 | 249,116 | 252,767 | 262,633 | 264,196 | |||||||||||||||
|
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|
|
|
|
|
|
|
| |||||||||||
Transportation only (MMcf): | 516,181 | 564,516 | 568,715 | 569,535 | 605,259 | |||||||||||||||
Revenues (in millions): | ||||||||||||||||||||
Bundled gas sales: | ||||||||||||||||||||
Residential | $2,089 | $1,991 | $1,953 | $2,574 | $2,378 | |||||||||||||||
Commercial | 464 | 474 | 496 | 792 | 766 | |||||||||||||||
Industrial | — | — | — | — | — | |||||||||||||||
Other gas utilities | 1 | — | — | — | — | |||||||||||||||
Miscellaneous | 101 | 49 | 55 | (30) | 87 | |||||||||||||||
Regulatory balancing accounts | 295 | 305 | 289 | 221 | 186 | |||||||||||||||
|
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|
|
|
|
|
|
|
| |||||||||||
Bundled gas revenues | 2,950 | 2,819 | 2,793 | 3,557 | 3,417 | |||||||||||||||
Transportation service only revenue | 400 | 377 | 349 | 333 | 340 | |||||||||||||||
|
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|
|
|
|
|
|
| |||||||||||
Operating revenues | $3,350 | $3,196 | $3,142 | $3,890 | $3,757 | |||||||||||||||
|
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|
|
| |||||||||||
Selected Statistics: | ||||||||||||||||||||
Average annual residential usage (Mcf) | 49 | 48 | 48 | 49 | 49 | |||||||||||||||
Average billed bundled gas sales revenues per Mcf: | ||||||||||||||||||||
Residential | $10.39 | $10.20 | $10.00 | $12.95 | $12.07 | |||||||||||||||
Commercial | 8.89 | 8.79 | 8.62 | 12.38 | 11.38 | |||||||||||||||
Industrial | — | — | — | — | — | |||||||||||||||
Average billed transportation only revenue per Mcf | 0.77 | 0.67 | 0.61 | 0.59 | 0.56 | |||||||||||||||
Net plant investment per customer | $1,721 | $1,637 | $1,557 | $1,344 | $1,375 |
(1) | In the years presented, the sale of excess supplies to parties located in California exceeded purchases from parties located in California. |
(2) | Includes fuel for the |
The Utility purchases natural gas to serve the Utility'sUtility’s core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility'sUtility’s portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2008,2011, the Utility purchased approximately 260,315279,157 MMcf of natural gas (net of the sale of excess supply) from suppliers. Consistent with existing CPUC policy directives, substantiallysupply of gas). Substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility'sUtility’s largest individual supplier represented approximately 10%9% of the total natural gas volume the Utility purchased during 2008.
The following table shows the total volume and the average price of natural gas in dollars per MMcf of the Utility'sUtility’s natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. Southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges, and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2008,the years presented below, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.
2008 | 2007 | 2006 | 2005 | 2004 | |||||||||||
MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | ||||||
Canada | 189,608 | $8.29 | 199,870 | $6.63 | 202,274 | $6.27 | 204,884 | $7.12 | 205,180 | $5.37 | |||||
California (1) | (53,126) | $9.24 | (23,065) | $6.77 | (13,401) | $7.04 | (18,951) | $7.70 | (9,108) | $4.89 | |||||
Other states (substantially all U.S. southwest) | 123,833 | $7.05 | 101,271 | $6.30 | 103,658 | $6.51 | 103,237 | $7.10 | 103,801 | $5.44 | |||||
Total/weighted average | 260,315 | $7.51 | 278,076 | $6.50 | 292,531 | $6.32 | 289,170 | $7.07 | 299,873 | $5.41 |
2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||||||||||||||||||||||
MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | MMcf | Avg. Price | |||||||||||||||||||||||||||||||
Canada | 197,151 | $ | 3.75 | 206,800 | $ | 4.03 | 190,485 | $ | 3.74 | 189,608 | $ | 8.29 | 199,870 | $ | 6.63 | |||||||||||||||||||||||||
California(1) | (23,988 | ) | $ | 4.45 | (32,910 | ) | $ | 4.63 | (41,714 | ) | $ | 4.16 | (53,126 | ) | $ | 9.24 | (23,065 | ) | $ | 6.77 | ||||||||||||||||||||
Other states (substantially all U.S. southwest) | 105,994 | $ | 3.74 | 96,338 | $ | 4.34 | 115,543 | $ | 3.50 | 123,833 | $ | 7.05 | 101,271 | $ | 6.30 | |||||||||||||||||||||||||
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Total/weighted average | 279,157 | $ | 3.69 | 270,228 | $ | 4.07 | 264,314 | $ | 3.57 | 260,315 | $ | 7.51 | 278,076 | $ | 6.50 |
(1) California purchases include supplies from various California producers and supplies transported into California by others.
The Utility'sUtility’s gas gathering system collects natural gas from third-party wells in northern and central California. During 2008,2011, approximately 6%5% of the gas transported on the Utility'sUtility’s system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream, and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 110.340 miles of gas gathering pipelines. The Utility receives gas well production at approximately 188180 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 87 California counties. Approximately 138111 MMcf per day of natural gas produced in northern California was delivered into the Utility'sUtility’s gas gathering system during 2008.
In 2008,2011, approximately 52% of the gas transported on the Utility'sUtility’s system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers'customers’ service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- CanadianStates-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies'companies’ pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”),GTN, which provides natural gas transportation services to a point of interconnection with the Utility'sUtility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has atwo firm transportation agreementagreements with GTN for these services. As described below, as part of the FERC-approved all-party settlement of GTN’s most recent general rate case, the Utility’s contract with GTN will be replaced beginning November 1, 2009 by three smaller contracts totaling the same amount with staggered terms.
During 2008,2011, approximately 42%20% of the gas transported on the Utility'sUtility’s system came from the westernU.S. Rocky Mountains. The Utility has firm transportation agreements with Ruby Pipeline to transport this gas from the U.S Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border.
During 2011, approximately 23% of the gas transported on the Utility’s system came from the southwestern United States, excluding California.States. The Utility has firm transportation agreements with Transwestern Pipeline Company, LLC and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility'sUtility’s natural gas transportation system in the area of California near Topock, Arizona.
The following table shows certain information about the Utility'sUtility’s firm natural gas transportation agreements in effect during 2008,at the end of 2011 to support the Utility’s needs for its core customers, including the contract quantities, contract durations, and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulatorsthe National Energy Board of Canada in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUC’s approval, extend eachmost of these natural gas transportation agreements. On the FERC-regulated pipelines, theThe Utility has eitherretains a right of first refusal or evergreen rights on most agreements, allowing it to renew natural gas transportation agreementsrenewal at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.
Pipeline | Expiration Date | Quantity MDth per day | Demand Charges for the Year Ended December 31, 2008 (In millions) | ||||
TransCanada NOVA Gas Transmission, Ltd. | 10/31/2011 | (1) | 619 | $29.5 | |||
TransCanada Foothills Pipe Lines Ltd., B.C. System | 10/31/2011 | 611 | 15.7 | ||||
Gas Transmission Northwest Corporation | 10/31/2009 | 610 | 89.6 | ||||
Transwestern Pipeline Company (1) | Various | 180 | 15.9 | ||||
El Paso Natural Gas Company (2) | Various | 267 | 17.2 |
Pipeline | Expiration Date | Quantity MDth per day | Demand Charges for the Year Ended December 31, 2011 (In millions) | |||
TransCanada NOVA Gas Transmission, Ltd.(1) | Various | 370 | $39.1 | |||
TransCanada Foothills Pipe Lines Ltd., B.C. System(2) | 10/31/2013 | 366 | 19.0 | |||
TransCanada Gas Transmission Northwest LLC(3) | Various | 360 | 68.1 | |||
Transwestern Pipeline Company(4) | Various | 193 | 17.3 | |||
El Paso Natural Gas Company(5) | Various | 202 | 23.3 | |||
Ruby Pipeline, LLC(6) | 10/31/2026 | 250 | 10.9 |
(1) | As of December 31, |
(2) | As of December 31, 2011, the Utility had two active contracts with TransCanada Foothills Pipe Lines Ltd., B.C. System with expiration dates of October 31, 2013. |
(3) | As of December 31, 2011, the Utility had two active contracts with TransCanada Gas Transmission Northwest LLC with expiration dates ranging from October 31, 2016 to October 31, 2020. |
(4) | As of December 31, 2011, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February |
As of December 31, |
(6) | The Utility has the option to reduce quantity (MDth per day) beginning with the twelfth year and annually thereafter through the end of the contract. |
Public Purpose and Customer Programs
California law requires the CPUC to authorize certain levels of funding for programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources through the collection of a public goods charge. The legislation authorizing the public goods charge expired on January 1, 2012. The CPUC has ordered the Utility to continue to collect in rates the amounts that were previously funded through the public goods charge for energy efficiency, renewables, and research and development, on an interim basis through 2012. California law also requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs, as discussed below. Additionally, the CPUC has authorized funding for demand response programs. For 2011, the Utility collected authorized revenue requirements of $731 million from electric customers and $161 million from gas customers to fund public purpose and other programs.
The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products. The CPUC has authorized a total of $1.3 billion to fund the Utility’s 2010-2012 energy efficiency programs. The CPUC has adopted a long-term energy efficiency strategic plan designed to encourage innovative market transformation activities, such as the pursuit of zero net energy buildings, in addition to traditional energy efficiency rebate programs.
The CPUC established an incentive ratemaking mechanism to encourage the California investor-owned utilities to promote energy efficiency and to meet the CPUC’s energy savings goals. In accordance with this mechanism, the CPUC has awarded the Utility incentive revenues totaling $130 million through December 31, 2011 for successful implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle and for the 2009 bridge year. It is uncertain what form of incentive ratemaking the CPUC will establish and what amount, if any, the Utility will be authorized to earn for future energy efficiency programs.
Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The CPUC authorized the Utility to collect $109 million to fund its 2009-2011 demand response programs. In addition, the CPUC authorized the Utility to collect $112 million through December 31, 2011 to implement its multi-year air conditioning direct load control program. Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies. The Utility anticipates that the CPUC will issue a decision providing funding for the 2012-2014 demand response programs during the first quarter of 2012.
Self-Generation Incentive Program and California Solar Initiative
The Utility administers the self-generation incentive program (“SGIP”) authorized by the all-party settlementCPUC to provide incentives to electricity and gas customers who install certain types of GTN’s most recent general rate caseclean or renewable distributed generation and energy storage resources that meet all or a portion of their onsite energy usage. In December 2011, the CPUC approved bycontinuing annual funding for the FERC on January 7, 2008,SGIP of approximately $36 million through 2014, with any carryover funds to be administered through 2015. The Utility also administers the California Solar Initiative (“CSI”) in its service territory. The CPUC has authorized the Utility has entered into three smaller contracts with GTN with terms that begin on November 1, 2009to collect approximately $1.1 billion from 2007 through 2016 to fund customer incentives for the installation of retail solar energy projects to serve onsite load, as well as to fund research, development, and terminate on various dates unless renewed, as follows:
Expiration Date | Quantity MDth per day | Estimated Demand Charges 2009-2011 (In millions) | ||||
10/31/2011 | 250 | $58 | ||||
10/31/2016 | 280 | 71 | ||||
10/31/2020 | 80 | 20 |
Low-Income Energy Efficiency Programs and California Alternate Rates for Energy
The CPUC has authorized the Utility has entered into a separate contract with GTN for firm transportation serviceto collect approximately $417 million to support the Utility’s needenergy efficiency programs for natural gas for electric power plant fuel. This new contract is for a quantity of 50 MDth/d for a 59-month term, July 1,low-income and fixed-income customers over 2009 through May 31, 2014.
GeneralEnvironmental Matters
The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility'sUtility’s personnel and the public. These laws and requirements relate to a broad range of activities, including:including the following:
the discharge of pollutants into the air, water, and soil;
the transportation, handling, storage and disposal of spent nuclear fuel;
the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, remediation and emergency response in connection with hazardous and radioactive substances;
the reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions; and
the environmental impacts of land use, including endangered species and habitat protection.
The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify, or replace equipment, acquire permits and/or marketableemission allowances or other emission credits for facility operations and clean-up, or decommission waste disposal areas at the Utility'sUtility’s current or former facilities and at third-party sites where the Utility’s wastes may have been disposed.
The Utility’s estimated costs to comply with environmental laws and regulations are based on current estimates and assumptions that are subject to change. In addition, the Utility is likely to incur costs as it develops and implements strategies to mitigate the impact of its operations on the environment, including climate change and its foreseeable impact on the Utility’s future operations. The actual amount of costs that the Utility will incur is subject to many factors, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner’s responsibility, the availability of recoveries or contributions from third parties, and the development of market-based strategies to address climate change. Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility'sUtility’s rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a special ratemaking mechanism described below under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims from customers (e.g., for costs“Recovery of cleaning up the Utility's facilities and sites where the Utility’s hazardous substances have been sent). This mechanism allows the Utility to include 90% of eligible hazardous waste remediation costs in the Utility's rates without a reasonableness review. (One exception to this is the Hinkley natural gas compressor site discussed below. The cost of environmental remediation associated with this site is not recoverable from customers.) Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility's customers. The balances of any insurance recoveries (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any
The Utility'sUtility’s electricity generation plants, natural gas pipeline operations, fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulate matter. In addition, various laws and regulations addressing climate change and greenhouse gas emissions (“GHG”) are being considered or implemented at the federal and state levels, as discussed below. Fossil fuel-fired plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies. In addition, greenhouse gas emissions from natural gas consumed by the Utility’s customers would be subject to regulation by the California Air Resources Board (“CARB”), as discussed below.
Federal Regulation. At the federal level, the U.S. Environmental Protection Agency (“EPA”) is charged with implementation and enforcement of the Clean Air Act. Although there have been several legislative initiatives have been introduced recently in Congress aimed at addressingattempts to address climate change through imposition of nation-widenationwide regulatory limits on GHG emissions, comprehensive federal legislation is unlikely to be enacted within the next few years. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions, including establishing an annual GHG reporting requirement. In June 2010, the EPA adopted the final “tailoring rule” to phase-in permit requirements for construction of GHGs. Nonew sources of GHG emissions, such legislation has yet been enacted by Congress, but extensive hearingsas power plants and discussionnatural gas compressor stations, if the GHG emissions from these sources would exceed certain thresholds. These permit requirements also apply to major modifications proposed to be made to existing facilities that emit GHGs that meet the threshold. The EPA rules require owners of these facilities to use the “best available control technology” to minimize GHG emissions. The uncertainty about what constitutes the “best available control technology” may cause permitting delays. In December 2011, the EPA released final mercury and air toxic standards for new emission sources. These
regulations set emission limits for new and existing sources of GHG emissions, specifically coal- and oil-fired power plants. While the Utility does not own any coal- or oil-fired power plants, it does procure a small portion of electricity from plants that use coal and oil. The EPA’s regulations could increase the price for this power. All of the EPA’s major GHG regulatory actions under the Clean Air Act, including the tailoring rule, are expectedbeing challenged in the coming year. federal court and are not likely to be resolved until mid- to late 2012, or later.
State Regulation.At the state level, California enacted Assembly Bill 32 (“the CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce the AB 32”), the California Global Warming Solutions Act of 2006, to address climate change.32. AB 32 requires the gradual reduction of GHG emissions in California to the 1990 levelslevel by 2020 on a schedule beginning in 2012. AB 32 also authorizes the2020. The CARB to monitor and enforce compliance with the GHG reduction program and to consider implementing market-based mechanisms, including trading of GHG emissions allowances. In 2007, the CARB adoptedestablished a state-wide GHG 1990 emissions baseline of 427 million metric tons of carbon dioxideCO2 (or its equivalent). This 1990 baseline serves to serve as the 2020 emissions reduction targetlimit for the state of California. (TheThe CARB has not yet determined specific GHG reduction limits applicable to the utility sector or individual utilities within the utility sector.) In 2007, the CARB also adopted a regulation that requires the California investor-owned utilities and other GHG emitters to file verified reports of their annual GHG emissions. On December 12, 2008, the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target, including increased reliance on renewable resources and energy efficiency and the development of a multi-sector cap-and-trade program. The CARB is required to adoptapproved various regulations to implement AB 32, including a state-wide, comprehensive “cap and trade” program that sets gradually declining limits (or “caps”) on the scoping plan not later than January 1, 2011 to becomeamount of GHGs that may be emitted by the major sources of GHG emissions. These regulations became effective on January 1, 2012.
The cap and trade program’s first two-year compliance period, which begins January 1, 2013, will apply to the electricity generation unlessand large industrial sectors. The next two-year compliance period, from January 1, 2015 through December 31, 2017, also will apply to the generation compliesnatural gas supply and transportation sectors. (The last compliance period, from January 1, 2018 through December 31, 2020, will apply to all sectors.) Before the first compliance period begins, the CARB will issue a fixed number of emission allowances (i.e., the rights to emit GHGs), some of which will be freely allocated to regulated electric distribution utilities for their customers’ benefit. The CARB will sell other allowances at an auction, the first of which is scheduled to be held on August 15, 2012. Emitters, i.e.,those entities with a compliance obligation, also can purchase “offset credits” from certified parties that develop environmental projects in sectors not regulated under the cap, such as reforestation and methane capture projects. These emitters can then use the offset credits to satisfy up to 8% of their compliance obligations. Allowances may be purchased and sold through a CARB-managed auction or in private transactions, while offset credits are available only through private transactions. On or before specified deadlines during and at the end of each compliance period, emitters must surrender allowances and offset credits, in an amount equal to their GHG emissions during the period, to the CARB. During 2012, the CARB is expected to complete additional cap-and-trade market design and implementation activities, and is expected to conduct market simulations to evaluate current market design.
The Utility’s compliance costs under the cap and trade program are expected to be passed through to customers through rates. The CPUC is conducting a rulemaking to develop rules for the allocation of auction revenues to the utilities’ electric customers and a proposed decision is scheduled to be issued in May 2012. Allocation of allowances to help reduce the compliance costs that the Utility may incur on behalf of the Utility’s small natural gas customers remains an open issue.
Increasing use of renewable energy supplies also is expected to help reduce GHG emissions in California. In April 2011, the California Governor signed legislation that requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy delivered to their customers to at least 33% of the total amount of electricity retail sales by 2020. (See “Electricity Generation Resources” above.) In December 2011, the CPUC approved various regulations to implement the new law, including the establishment of renewable energy targets for each compliance period. (See “Renewable Energy Resources” above for more information.)
Climate Change Mitigation and Adaptation Strategies.During 2011, the Utility continued its programs to develop strategies to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to develop its strategy to plan for the actions that it will need to take to adapt to the likely impacts that climate change will have on the Utility’s future operations. With respect to electric operations, climate scientists project that, sometime in the next several decades, climate change will lead to increased electricity demand due to more extreme and frequent hot weather events. Climate scientists also predict that climate change will result in significant reductions in snowpack in parts of the Sierra Nevada Mountains. This impact could, in turn, affect the Utility’s hydroelectric generation. At this time, the Utility does not anticipate that reductions in Sierra Nevada snowpack will have a significant impact on its hydroelectric generation, due in large part to its adaptation strategies. For example, one adaptation strategy the Utility is developing is a combination of operating changes that may include, but are not limited to, higher winter carryover reservoir storage levels, reduced conveyance flows in canals and flumes in response to an increased portion of precipitation falling as rain rather than snow, and reduced
discretionary reservoir water releases during the late spring and summer. If the Utility is not successful in fully adapting to projected reductions in snowpack over the coming decades, it may become necessary to replace some of its hydroelectric generation with electricity from other sources, including GHG-emitting natural gas-fired power plants.
With respect to natural gas operations, the Utility has taken steps to reduce the release of methane, a GHG released as part of the delivery of natural gas. The Utility has replaced a substantial portion of its older cast iron and steel gas mains and implemented a technique called cross-compression, a process by which natural gas is transferred from one pipeline to another during large pipeline construction and repair projects. Cross-compression reduces the amount of natural gas vented to the atmosphere by 75% to 90%.
The Utility believes its strategies to reduce GHG emissions—such as energy efficiency and demand response programs, infrastructure improvements, and the support of renewable energy development—are also effective strategies for adapting to the expected increased demand for electricity in extreme hot weather events likely to be caused by climate change. PG&E Corporation and the Utility are also assessing the benefits and challenges associated with various climate change policies and identifying how a comprehensive program can be structured to mitigate overall costs to customers and the economy as a whole while ensuring that the environmental objectives of the program are met.
PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility was a charter member of the California Climate Action Registry (“CCAR”) and voluntarily reported its GHG emissions to CCAR on an annual basis from 2002 through 2008. The Utility has since voluntarily reported its GHG emissions to The Climate Registry (“TCR”), a successor non-profit to CCAR, that has a reporting and measurement standard applicable to most industry sectors across North America. Since 2009, the Utility has also complied with AB 32’s annual GHG emission performance standard. As required by Senate Bill 1368, on January 25, 2007,reporting requirements, and in 2011, the CPUC adopted an interimUtility began reporting the GHG emissions performance standardfrom some of 1,100 pounds of carbon dioxide per MWh that appliesits facilities and operations to the EPA under its new commitments for baseload electricity procured under contracts with a term of five years or longer or generated byrequirements. In 2012, the Utility. After a state-wideUtility will include the GHG emissions limit is establishedfrom the natural gas supplied to end-users and isthe vented and fugitive emissions from its natural gas system in operation,its report to the EPA. Beginning in 2012, the Utility will annually report to the CARB the GHG emissions from customers’ use of natural gas.
PG&E Corporation and the Utility also publish third-party-verified GHG emissions data in their annual Corporate Responsibility and Sustainability Report. As a result of the time necessary for a thorough, third-party verification of the Utility’s GHG emissions in accordance with AB 32, the CPUC will re-evaluatestandards developed by TCR, emissions data for 2010 are the most recent data available. For information about the sources of electric generation that the Utility delivered to customers in 2011, see “Electric Utility Operations-Electric Generation Resources” above.
Total 2010 GHG Emissions by Source Category
Source | Amount (per million metric tonnes CO2 – equivalent) | |
Delivered Electricity(1) | 17.21 | |
Electricity Transmission and Distribution Line Losses | 1.11 | |
Process and Fugitive Emissions from Natural Gas Systems | 1.48 | |
Gas Compressor Stations | 0.28 | |
Transportation | 0.11 | |
Facility Gas and Electricity Use | 0.05 | |
Electrical Equipment | 0.07 | |
Total | 20.31 | |
(1)Since the Utility purchases a portion of its interimelectricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s total emissions and the Utility’s emission rate for delivered electricity. Emissions data for the Utility’s owned generation resources is shown below.
Benchmarking Greenhouse Gas Emissions for Delivered Electricity
The Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2010 was 443 pounds of CO2 per MWh, which is a significant decrease from the 2009 emissions rate of 575 pounds of CO2 per MWh. The Utility’s 2010 emissions rate as compared to the national and California averages for electric utilities is shown in the following table:
Amount (Pounds of CO2 per MWh) | ||||
U.S. Average(1) | 1,293 | |||
California’s Average(1) | 681 | |||
Pacific Gas and Electric Company(2) | 443 |
(1) Source: Environmental Protection Agency eGRID 2010 Version 1.1, which contains year 2007 information, configured to reflect the electric power industry’s current structure as of December 31, 2010. This is the most up-to-date information available from EPA.
(2) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s total emissions and the Utility’s emission rate for delivered electricity.
Emissions Data for Utility-Owned Generation
In addition to GHG emissions performance standard and determine whether to continue, modify or rescind it.
2010 | 2009 | |||||||
Total NOx Emissions (tons) | 904 | 1,258 | ||||||
NOx emissions rates (pounds/MWh) | ||||||||
Fossil fuel-fired plants | 0.49 | 0.82 | ||||||
All plants | 0.06 | 0.09 | ||||||
Total SO2 Emissions (tons) | 42 | 37 | ||||||
SO2 emissions rates (pounds/MWh) | ||||||||
Fossil fuel-fired plants | 0.023 | 0.02 | ||||||
All plants | 0.003 | 0.0026 | ||||||
Total CO2 Emissions (metric tons) | 1,545,892 | 1,401,487 | ||||||
CO2 emissions rates (pounds/MWh) | ||||||||
Fossil fuel-fired plants | 943 | 1,016 | ||||||
All plants | 106 | 110 | ||||||
Other Emissions Statistics | ||||||||
Sulfur Hexafluoride (“SF6”) Emissions | ||||||||
Total SF6 Emissions (metric tons CO2- equivalent) | 69,066 | 62,129 | ||||||
SF6 emissions leak rate | 1.8% | 1.7% |
There is continuing uncertainty about the status of state and federal regulations issued under Water Quality
Section 316(b) of the federal Clean Water Act which requirerequires that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts. In July 2004,On April 20, 2011, the U.S. Environmental Protection Agency (“EPA”) issuedEPA published draft regulations that propose specific reductions for impingement (which occurs when larger organisms are caught on water filter screens) and provide a case-by-case site specific assessment to implement Section 316(b) intended to reduce impacts to aquaticestablish compliance requirements for entrainment (which occurs when organisms by establishing a set of performance standards forare drawn through the cooling water intake structures. Thesesystem). The proposed site specific assessment allows for the consideration of a variety of factors including social costs and benefits, energy reliability, land availability, and non-water quality adverse impacts. The draft regulations provided each facility with a number of compliance optionswere subject to public comment and permitted site-specific variances based on a cost-benefit analysis. The EPAfinal regulations also allowedare not expected until July 2012.
The Utility'sUtility’s facilities are subject to the requirements issued by the EPA under the federal Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site, and in some cases corporate successors to the operators or arrangers. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources, and the costs of required health studies. In the ordinary course of the Utility'sUtility’s operations, the Utility generates waste that falls within CERCLA'sCERCLA’s definition of hazardous substances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state, and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling, and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws, and other environmental requirements.
The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites,(“MGP”) sites; current and former power plant sites,sites; former gas gathering and gas storage sites; sites where natural gas compressor stations are located; current and former substations, service center and general construction yard sites; and sites wherecurrently and formerly used by the Utility stores, recycles and disposesfor the storage, recycling, or disposal of potentially hazardous materials.substances. Under federal and California laws, the Utility may be responsible for remediation of hazardous
Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. For more information about environmental remediation liabilities, see “Environmental Matters,” “Critical Accounting Polices,” and Note 15: Commitments and Contingencies–Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report which information is incorporated herein by reference and included in Exhibit 13 to this report.
Operations at the Utility'sUtility’s current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal and fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies. Additionally, the Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. Remedial investigations are substantially complete,The DTSC approved the soil and the Utility anticipates that the California Department of Toxic Substances Control will approve thegroundwater remediation plan byin June 2010 and remediation pursuant to the second quarter of 2009.plan is underway. The Utility spent approximately $1$34 million in 20082011. Fossil fuel-fired Units 1 and estimates that it will spend approximately $12 million2 of the Utility’s Humboldt Bay power plant shut down in 2009September 2010, and approximately $15 millionare now in 2010 for remediation at this site.
Former Manufactured Gas Plant Sites
The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain retired manufactured gas plantMGP sites. During their operation, from the mid-1800s through the early 1900s, manufactured gas plantsMGPs produced lampblack and coal tar residues. The residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. There are 95 such sites within the Utility’s service territory that are owned by the Utility or third parties. The Utility has determined that it is liable for the remediation of 41 sites, is potentially liable for remediation of an additional 24 sites, and is not liable for remediation at the remaining 30 sites. The Utility has a program, in cooperationbeen coordinating with environmental agencies and third partythird-party owners to evaluate and take appropriate action to mitigate any potential healthenvironmental concerns at 41 MGP sites that the Utility owned or environmental hazards atoperated in the 41past. Of these sites for whichowned or operated by the Utility, 40 sites have been or are in the process of being investigated and/or remediated, and the Utility is liable.developing a strategy to investigate and remediate the last site. The Utility spent approximately $12$33 million in 2008 and expects to spend approximately $27 million in 2009 and $20 million in 20102011 on these sites. The Utility expects that expenses at these sites will increase as remedial actions related to these sites are approved by regulatory agencies and claims by third party owners are settled. Although it is likely that the Utility will incur remediation costs related to some of these sites, the Utility cannot quantify the potential amount.
Third-Party Owned Disposal Sites
Under environmental laws, such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility'sUtility’s facilities, or to pay for associated clean-up costs or natural resource damages. The Utility is currently aware of fivetwo such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility substantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and led the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several parties that sent waste to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and remediation measures. Other responsible parties are involved with the Utility in investigation and cleaning up the three other disposal sites with oversight from the regulatory agencies.
Natural Gas Compressor Stations
The Utility contributes to these sites under cost sharing agreements or court approved settlements
The Utility’s remediation and abatement efforts at both the Hinkley and Topock natural gas compressor stations. At Hinkley,site are subject to the Utility is cooperating withregulatory authority of the California Regional Water Quality Control Board, Lahontan Region (“Regional Board”). The Regional Board has issued numerous cleanup and abatement orders directing the Utility to evaluate and remediate the chromium groundwater plume. Measures have been implemented to control movement offully investigate the plume while full-scale in-situ treatment systems operateof hexavalent chromium and implement interim remedial measures to both reduce the mass of the underground plume and control movement of the plume. AnIn August 2010, the Utility filed a comprehensive feasibility study with the Regional Board that included an evaluation of possible alternatives for a final groundwater remediation plan. The Utility filed several addendums to its feasibility study based on additional analyses of remediation alternatives and further information from the performanceRegional Board. In September 2011, the Utility submitted a final remediation plan to the Regional Board. In October 2011, the Regional Board issued an amended cleanup and abatement order that requires the Utility to provide an interim and permanent replacement water system for certain properties with domestic wells containing hexavalent chromium concentrations above the 3.1 parts per billion (“ppb”) background level and propose a method to evaluate individual wells with hexavalent chromium concentrations below 3.1 ppb to determine if they have been impacted by the Utility’s past operations. The order requires that the Utility provide evidence to prove that the provided water meets primary and secondary drinking water standards and contains hexavalent chromium in concentrations no greater than 0.02 ppb. The order notes that for purposes of this standard, drinking water must test below the reporting limit of 0.06 ppb due to the limitation of laboratory analysis of low levels of chromium. The Utility has filed a petition with the California Water Board to request that the board determine that the Utility is not required to comply with these interim remedy measures, as well as possible future measures, is underway as partprovisions of the developmentorder, in part, because the Utility believes that it is not feasible to implement the ordered actions and that the ordered actions are not supported by California law. The Regional Board’s response to the petition is due by February 20, 2012.
For the year ended December 31, 2011, the Utility increased its provision for environmental remediation liabilities associated with the Hinkley site by $140 million, which resulted primarily from changes in costs estimates and assumptions associated with these developments. For more information, see Note 15 Commitments and Contingencies of a final remedythe Notes to the Consolidated Financial Statements. During 2011, the Utility spent $36 million for remediation activities at the Hinkley site. In 2008, theThe Utility spent approximately $15 million on remediation activities at Hinkley, and currently estimates it will spend at least $16 million in 2009 and $6 million in 2010. Environmentalis unable to recover remediation costs associated withfor the Hinkley natural gas compressor site are not recoverable from customers.
The Utility’s investigation and remediation activities at the Topock gas compressor station located near Needles, California,are subject to oversight by the DTSC and the U.S. Department of the Interior. The Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River. In addition,January 2011, the regulatory agencies approved the Utility’s final remediation plan under which the Utility is workingwill implement an in-situ treatment project to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. To implement the final remedy, the Utility plans to install a significant number of additional injection and extraction wells and an associated piping system. The regulatory approval of the environmental impact report associated with the agencies to complete investigations at this site and to develop a long-term plan for clean up of the plume. A final cleanup draftremediation plan has been developed for agency and stakeholder review; approval of a final version of that plan is scheduled to occurchallenged in the Sacramento Superior Court by the first quarter of 2010.Fort Mojave Indian Tribe. The tribe alleges that the cultural mitigation requirements contained in the environmental impact report was inadequate. The Utility, the tribe and DTSC are engaged in settlement negotiations to address the tribe’s concerns. In 2008,2011, the Utility spent approximately $23$14 million on the interim measures and for work on the long term site solution. The Utility currently estimates that it will spend at least $19 million
The Utility does not expect that it will incur any material expenditures related to any remediation at itsthe Kettleman natural gas compressor station.
Recovery of Environmental Remediation Costs
The CPUC has approved a ratemaking mechanism under which the Utility is authorized to recover environmental costs associated with the clean-up of most sites that contain hazardous substances, including former MGP sites, third-party disposal sites, and natural gas compressor sites (other than the Hinkley site). This mechanism allows the Utility to include 90% of eligible hazardous substance cleanup costs in the Utility’s rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste
remediation sites are assigned to the Utility’s customers. The balances of any insurance recoveries (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility’s claims against third parties associated with hazardous waste remediation sites are retained by the Utility, with the remainder, 90% of any such recoveries, assigned to the Utility’s customers.
The CPUC has historically authorized the Utility to recover 100% of its remediation costs for decommissioning fossil fuel-fired generation facilities and sites through decommissioning funds collected in rates, and the Utility believes it is probable that it will continue to recover these costs in the future. The CPUC also authorized the Utility to make a one-time recovery of $139 million in rates for pre-closing environmental remediation liabilities associated with fossil fuel-fired generation facilities that the Utility sold in 1998 and 1999 in connection with electric industry restructuring. The remaining liability at these sites is $81 million. Any future changes to these liabilities will impact PG&E Corporation’s and the Utility’s financial results. The Utility expects to recover labor and other administrative costs associated with environmental remediation through other ratemaking mechanisms. Finally, the Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to customers.
As part of the Nuclear Waste Policy Act of 1982, Congress authorized the DOEU.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities'utilities’ spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay. The DOE failed to develop a permanent storage site by January 31, 1998. The Utility believes that the existing spent fuel pools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until October 2010 for Unit 1 and May 2011 for Unit 2. Because the DOE failed to develop a permanent storage site,meet its contractual obligations to dispose of nuclear waste, the Utility obtained a permit from the NRC to buildconstructed an on-siteinterim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024. After various parties appealed the NRC’s issuance of the permit,On February 15, 2011, the U.S. Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of a terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats. In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.
The Utility and other nuclear power plant owners sued the DOE for breachto recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92 million of contract. In October 2006,costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims found the DOE had breached its contract and awarded the Utility approximately $42.8 million$89 million. The DOE filed an appeal of the $92 million incurred bythis decision on May 28, 2010. On August 3, 2010, the Utility through 2004 to construct on-site storage at Diablo Canyon and Humboldt Bay Unit 3. Followingfiled two complaints against the Utility’s appeal of the award,DOE in the U.S. Court of Appeals for the Federal Circuit reversed the lower court on issues relatingClaims seeking to the calculation of damages and ordered the lower court to re-calculate the award. Although various motions by the DOE for reconsideration are still pending, the judge in the lower court conducted a status conference on January 15, 2009 and has scheduled another conference for July 9, 2009. The Utility expects the final award will approximate $91 million forrecover all costs incurred through 2004 and that the Utility will recover all of its costs incurred after 2004since 2005 to build on-site storage facilities.storage. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the DOE will be credited to customers through rates.customers.
The Utility'sUtility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding, which is used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in 2044;2044, that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin in 2025 and be completed in 2041;2041, and that decommissioning of Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in 2015. A premature shutdown of the Diablo Canyon units would increase the likelihood of an earlier start to decommissioning. The Utility’s decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility'sUtility’s nuclear power plants. Actual decommissioning costs may vary from these estimates to the extent the assumptions on which the estimates are based (such as a result of changes in assumptions such asabout decommissioning dates, regulatory requirements,
customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility'sUtility’s nuclear facilities.
In April 2009, the Utility filed an application in the 2009 Nuclear Decommissioning Triennial Proceeding with new decommissioning cost estimates and other funding assumptions, such as projected cost escalation factors and projected earnings of the funds for 2010, 2011, and 2012. In July 2010, the CPUC issued a decision in the first phase of the proceeding to determine the annual revenue requirement for the decommissioning trust. The CPUC has not yet issued a decision in the second phase of the proceeding which is evaluating whether to broaden investment options available to the trusts.
For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 132: Summary of Significant Accounting Policies– Nuclear Decommissioning Trusts, of the Notes to the Consolidated Financial Statements in the 20082011 Annual Report.
ElectricEndangered Species
Many of the Utility’s facilities and Magnetic Fields
A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading “Risk Factors” in the MD&A in the 20082011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility'sUtility’s electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under “Electric Utility Operations” and “Natural Gas Utility Operations.”Operations” which information is incorporated herein by reference. In total, the Utility occupies 9.8 million square feet of real property, including 8.5 million square feet that the Utility owns. Of the 9.8 million square feet of occupied real property, approximately 1.7 million square feet represent the Utility'sUtility’s corporate headquarters located in several Utility ownedUtility-owned buildings in San Francisco, California. The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities.
The Utility currently owns approximately 167,000 acres of land, including approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement. Approximately 75,000 acreswatershed lands. As part of this land may be donated in fee and encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility agreed to protect its watershed lands with conservation easements or equivalent protections, and/or donate up to approximately 75,000 acres of its watershed lands to public entities or qualified non-profit conservation organizations. (The Utility will not donate watershed lands that contain the Utility’s or a joint licensee’s hydroelectric generation facilities or is otherwise used for utility operations, but this land may be encumbered with conservation easements.) The Utility formed an entity,a non-profit organization, the Pacific Forest Watershed Lands Stewardship Council (“Council”) to oversee the development and implementation of a Land Conservation Plan (“LCP”) that will articulate the long-term
management objectives for the 140,000 acres.watershed lands. The Council is governed by an 18-member Boardboard of Directors that representsdirectors, one of whom was appointed by the Utility. The other members represent a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Utility has appointed 1 out of 18
PG&E Corporation also leases approximately 74,00082,000 square feet of office space from a third party in San Francisco, California. This lease expiresCalifornia, of which 40,000 square feet will expire in 2012.
In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business.
The Utility'sUtility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the Central Coast Board.Regional Water Quality Control Board (“Central Coast Board”). This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility'sUtility’s Diablo Canyon power plant'splant’s discharge was not protective of beneficial uses.
In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board agreed to find that the Utility'sUtility’s discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement agreement. On June 17, 2003, the settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General'sGeneral’s Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDESCanyon’s permit.
At its July 10, 2003 meeting, the Central Coast Board did not renew the NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists'scientists’ draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists'scientists’ recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers. The
In addition, the California Water Board is developing a stateBoard’s policy foron once-through cooling and regulations that are expected to be issued by the implementation of Section 316(b) of the Clean Water Act, the adoption of whichEPA in July 2012 could affect future negotiations between the Central Coast Board and the Utility. For more information aboutUtility regarding the draft state policy, see “Environmental Matters—status of the 2003 settlement agreement. (See “Item 1. Business–Environmental Matters–Water Quality” above.
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their Utility'sUtility’s financial condition or results of operations.
Complaints Filed byHinkley Natural Gas Compressor Station
As previously disclosed, groundwater at the Utility’s Hinkley natural gas compressor station contains hexavalent chromium as a result of the Utility’s past operating practices. At the Hinkley site, the Utility is cooperating with the California Attorney GeneralRegional Water Quality Control Board, Lahontan Region (“Regional Board”) to evaluate and remediate the chromium groundwater plume. The Regional Board has issued several orders directing the Utility to implement interim remedial measures to both reduce the mass of the underground plume of hexavalent chromium and to monitor and control movement of the plume. In September 2011, the Utility submitted a final remediation plan to the Regional Board that recommends a combination of remedial methods, including using pumped groundwater from extraction wells to irrigate agricultural land and in-situ treatment of the contaminated water. On February 2, 2012, the Regional Board and the City and CountyUtility reached a settlement of San Francisco
For more information about the Utility’s remediation activities at the Hinkley site, see the section of MD&A entitled “Environmental Matters” in the 2011 Annual Report.
Litigation Related to the San Francisco (“Superior Court”)Bruno Accident
Approximately 100 lawsuits involving third-party claims for personal injury and property damage, including two class action lawsuits, have been filed against PG&E Corporation and its directors, as well as against directorsthe Utility in connection with the San Bruno accident on behalf of approximately 370 plaintiffs. The lawsuits seek compensation for personal injury and property damage, and other relief, including punitive damages. The Utility stated publicly that it is liable for the San Bruno accident and will take financial responsibility to compensate all of the Utility, based on allegationsvictims for the injuries they suffered as a result of unfair or fraudulent business acts or practices in violation of California Businessthe accident. These cases have been coordinated and Professions Code Section 17200 (“Section 17200”). Among other allegations, the California Attorney General alleged that past transfers of funds from the Utilityassigned to PG&E Corporation during the period from 1997 through 2000 (primarilyone judge in the form of dividends and stock repurchases), and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis.
Additionally, a purported shareholder derivative lawsuit was filed following the San Bruno accident to seek recovery on February 26, 2009.
For more information regarding the litigation related to the San Bruno accident, see the section of MD&A entitled “Natural Gas Matters” in the 2011 Annual Report. See also Note 15: Commitments and Contingencies–Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report, which discussion is incorporated into this Item 3 by reference and included in Exhibit 13 to this report.
Pending Investigations Regarding the San Bruno Accident and Natural Gas Matters
As described below, the CPUC has issued three orders to institute investigations (“OII”) pertaining to various aspects of the Utility’s natural gas transmission system, including an investigation of the San Bruno accident. If the CPUC determines that the Utility violated applicable law, rules or orders, in connection with the CPUC’s investigations, the CPUC can impose penalties of up to $20,000 per day, per violation. (For violations that are considered to have occurred on or after January 1, 2012, the statutory penalty has increased to a maximum of $50,000 per day, per violation.) As described below, a criminal investigation into the San Bruno accident also was commenced by federal and state authorities.
For more information, see the section of MD&A entitled “Natural Gas Matters” in the 2011 Annual Report and Note 15: Commitments and Contingencies–Legal and Regulatory Contingencies, of the Notes to the Consolidated Financial Statements in the 2011 Annual Report, which discussion is incorporated into this Item 3 by reference and included in Exhibit 13 to this report.
CPUC Investigation Regarding Utility’s Facilities Records for its Natural Gas Pipelines. On February 24, 2011, the CPUC issued an OII pertaining to safety recordkeeping for the Utility’s gas transmission pipeline (Line 132) that ruptured in the San Bruno accident, as well as for its entire gas transmission system. The CPUC will determine (1) whether the Utility’s recordkeeping practices for its gas transmission pipeline system and its knowledge of its own gas transmission pipeline system (and, in particular, the San Bruno pipeline) was deficient and unsafe, and (2) whether the Utility thereby violated applicable law and safety standards. Among other matters, this phase will determine whether the San Bruno accident would have been preventable by the exercise of safe procedures and/or accurate and effective technical recordkeeping in compliance with the law. The CPUC will consider whether the Utility’s approach to recordkeeping stems from corporate-level management policies and practices and, if so, whether such practices and policies contributed to recordkeeping violations that adversely affected safety. The CPSD is scheduled to file its report on the Utility’s recordkeeping practices on March 5, 2012. Evidentiary hearings for the investigation are scheduled for September 2012 with a final decision expected in February 2013.
CPUC Investigation Regarding Class Location Designations for Pipelines. On November 10, 2011, the CPUC issued an OII pertaining to the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density. Under federal and state regulations, the class location designation of a pipeline is based on the types of buildings, population density, or level of human activity near the segment of pipeline, and is used to determine the MAOP up to which a pipeline can be operated. In the OII, the CPUC referred to the Utility’s June 30, 2011 class location study, in which the Utility reported that the class designations for some of its transmission pipeline segments had changed from what was reflected in the Utility’s Geographical Information System (“GIS”). Among other issues, the CPUC will determine whether the Utility failed to conduct class location studies when required, failed to adequately patrol and conduct continuing surveillance of its pipeline transmission system, failed to replace pipeline segments or reduce MAOP when the class location designation of a segment changed, and failed to furnish and maintain adequate, efficient, just and reasonable natural gas transmission service.
On January 17, 2012, the Utility reported that 162 miles of pipeline had a current class location higher than reflected in its GIS. Most of the misclassifications were due to the Utility’s failure to correctly identify development or well-defined areas near the pipeline. The Utility stated that some segments had been incorrectly classified since 1971. The Utility also determined that it had not timely performed a class location study for certain segments and did not confirm the MAOP of those segments for which the Utility had not timely identified a change in class location. On February 2, 2012, the Utility filed an update reporting that approximately 10 miles of pipeline had been operating at an MAOP higher than allowed for their current class location.
A prehearing conference was held on February 3, 2012 at which the assigned administrative law judge (“ALJ”) set April 2, 2012 as the date for the Utility to submit a second update reporting the final results of its validation of the class location data. The ALJ will set a second prehearing conference during the week of April 16, 2012.
CPUC Investigation Regarding San Bruno Accident. On January 12, 2012, the CPUC issued an OII to determine whether the Utility violated applicable laws, rules, orders, requirements, and industry safety standards in connection with the San Bruno accident. The CPUC stated that the scope of the investigation will include all past operations, practices and other events or courses of conduct that could have led to or contributed to the San Bruno accident, as well as, the Utility’s compliance with CPUC orders and resolutions issued since the date of the San Bruno accident. The CPUC cited the findings and allegations made by the CPSD in its investigative report released on January 12, 2012. In its report, the CPSD alleged that the San Bruno accident was caused by the Utility’s failure to follow accepted industry practice when installing the section of pipe that failed, the Utility’s failure to comply with federal pipeline integrity management requirements, the Utility’s inadequate recordkeeping practices, deficiencies in the Utility’s data collection and reporting system, inadequate procedures to handle emergencies and abnormal conditions, the Utility’s deficient emergency response actions after the incident, and a systemic failure of the Utility’s corporate culture that emphasized profits over safety. The CPUC noted that the CPSD’s investigation is ongoing and that the CPSD could raise additional concerns for the CPUC to consider.
The CPSD report also discussed the findings of an independent consulting firm engaged by the CPUC to conduct an audit of the Utility’s natural gas transmission and storage expenditures from 1996 to 2010. The CPSD report stated that the purpose of the audit was to determine whether the amounts that the CPUC authorized for gas pipeline safety investments were actually spent on safety investments. The CPSD made various recommendations based on its allegations and the findings in the consultant’s audit report. During this time, the consultant’s audit report alleged that the Utility spent less on capital expenditures and operation and maintenance expense than it recovered in rates, by $95 million and $39 million, respectively, and alleged that the Utility collected $430 million more in revenues than needed to earn its authorized ROE. Among other recommendations, the CPSD recommended that the Utility should use such amounts to fund future gas transmission expenditures and operations.
In the OII, the CPUC stated that it may consider ordering the Utility to implement the recommendations made in the CPSD’s report, in order to improve and ensure system-wide safety and reliability. In addition, the CPUC stated that it will decide in a separate proceeding whether the Utility’s ratepayers or shareholders, or both, will pay for the Utility’s cost of testing, pipe replacement, or other costs, noting that some costs may stem from the San Bruno pipeline rupture or from recordkeeping deficiencies, both of which could be significant.
At a prehearing conference held on February 14, 2012, the ALJ set a procedural schedule for the parties to conduct discovery and submit testimony before evidentiary hearings begin on September 17, 2012.
Criminal Investigation Regarding the San Bruno Accident. On June 9, 2011, the Utility was notified that representatives from the U.S. Department of Justice, the California Attorney General’s Office, and CCSF’s allegations have no merit and will continue to vigorously respond to and defend against the litigation.San Mateo County District Attorney’s Office are conducting an investigation of the San Bruno accident. The Utility is cooperating with the investigation. PG&E Corporation believesand the Utility are unable to estimate the amount (or range of amounts) of reasonably possible losses associated with any civil or criminal penalties that could be imposed on the ultimate outcomeUtility.
CPUC Investigation Regarding Substation Construction Permit
On June 10, 2011, the CPUC issued an order to investigate whether the Utility failed to comply with the CPUC’s November 9, 2009 decision granting the Utility’s request for a permit to construct a substation when the Utility removed an almond tree orchard to prepare the site for construction. Although the Utility believed it complied with the decision in all material respects, the Utility entered into a settlement agreement with the CPUC staff to resolve the investigation that was approved by the CPUC in January 2012. Pursuant to the approved settlement agreement, the Utility has paid a fine of this matter would not result in a material adverse effect on PG&E Corporation’s financial condition or results of operations.
Item 4.Submission of Matters to a Vote of Security HoldersMine Safety Disclosures
Not applicable.
The names, ages and positions of PG&E Corporation “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934 (“Exchange Act”) at February 20, 2009, are1, 2012 were as follows:
Name | Age | Position | ||
Anthony F. Earley, Jr. | Chairman of the Board, Chief Executive Officer, and President | |||
Kent M. Harvey | Senior Vice President and Chief | |||
Christopher P. Johns | ||||
Hyun Park | 50 | |||
Senior Vice President and General Counsel | ||||
Greg S. Pruett | Senior Vice President, Corporate | |||
John R. Simon | ||||
Senior Vice President, Human Resources |
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 20, 2009,1, 2012, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
Name | Position | Period Held Office | ||||
Anthony F. Earley, Jr. | Chairman of the Board, Chief Executive Officer, and President | September | ||||
October 1, 2010 to September | ||||||
Chairman of the Board and Chief Executive Officer, | ||||||
Kent M. Harvey | Senior Vice President and Chief Financial Officer | |||||
Senior Vice President, Financial Services, Pacific Gas and Electric Company | August 1, 2009 to present | |||||
Senior Vice President and Chief Risk and Audit Officer | October 1, 2005 to | |||||
Christopher P. Johns | ||||||
Senior Vice President and Chief Financial Officer | May 1, 2009 to July 31, 2009 | |||||
Senior Vice President, Financial Services, Pacific Gas and Electric Company | May 1, 2009 to July 31, 2009 | |||||
Senior Vice President, Chief Financial Officer, and Treasurer | October 4, 2005 to | |||||
Senior Vice President and Treasurer, Pacific Gas and Electric Company | June 1, 2007 to | |||||
Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company | October 1, 2005 to May 31, 2007 | |||||
Hyun Park | Senior Vice President and General Counsel | November 13, 2006 to present | ||||
Greg S. Pruett | Senior Vice President, | |||||
Senior Vice President, Corporate Affairs, Pacific Gas and Electric Company | November 1, 2009 to present | |||||
Senior Vice President, Corporate Relations | November 1, 2007 to | |||||
Senior Vice President, Corporate Relations, Pacific Gas and Electric Company | March 1, 2009 to October 31, 2009 | |||||
Vice President, Corporate Relations | March 1, 2007 to October 31, 2007 | |||||
Vice President, Communications and Marketing, American Gas Association | April 10, 2006 to February 23, 2007 | |||||
John R. Simon | Senior Vice President, Human Resources | April 16, 2007 to present |
Name | Position | Period Held Office | ||
Senior Vice President, Human Resources, Pacific Gas and Electric Company | April 16, 2007 to present | |||
Executive Vice President, Global Human Capital, TeleTech Holdings, Inc. | March 21, 2006 to April 13, 2007 | |||
The names, ages and positions of the Utility'sUtility’s “executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at February 20, 2009, are1, 2012 were as follows:
Name | Age | Position | ||
Anthony F. Earley, Jr. | Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation | |||
Christopher P. Johns | 51 | President | ||
Nickolas Stavropoulos | Executive Vice President, Gas Operations | |||
Geisha J. Williams | 50 | Executive Vice President, Electric Operations | ||
Karen A. Austin | 50 | Senior Vice President and Chief | ||
Desmond A. Bell | Senior Vice President, Safety and Shared Services | |||
Thomas E. Bottorff | Senior Vice President, Regulatory Relations | |||
Helen A. Burt | Senior Vice President and Chief Customer Officer | |||
John T. Conway | Senior Vice President, | |||
Kent M. Harvey | Senior Vice President, | |||
Hyun Park | 50 | |||
Senior Vice President and General Counsel, PG&E Corporation | ||||
Greg S. Pruett | Senior Vice President, Corporate | |||
John R. Simon | ||||
Senior Vice President, Human Resources | ||||
Fong Wan | Senior Vice President, Energy Procurement | |||
Dinyar B. Mistry | ||||
Vice President, |
All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 20, 20091, 2012, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
Name | Position | Period Held Office | ||||
Anthony F. Earley, Jr. | Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation | September | ||||
Executive Chairman of the Board, DTE Energy Company | October 1, 2010 to September 12, 2011 | |||||
Chairman of the Board and Chief Executive Officer, | ||||||
Christopher P. Johns | President | |||||
Senior Vice President, Financial Services | May 1, 2009 to July 31, 2009 | |||||
Senior Vice President and Chief Financial Officer, PG&E Corporation | ||||||
Senior Vice President and Treasurer | June 1, 2007 to April 30, 2009 | |||||
Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation | October 4, 2005 to April 30, 2009 | |||||
Senior Vice President, Chief Financial Officer, and Treasurer | October 1, 2005 to May 31, 2007 | |||||
Nickolas Stavropoulos | Executive Vice President, Gas Operations | June 13, 2011 to present |
Name | Position | Period Held Office | ||||
Executive Vice President and Chief Operating Officer, U.S. Gas Distribution, National Grid | August 2007 to March 31, 2011 | |||||
President, KeySpan Energy Delivery | June 2004 to August 2007 | |||||
Geisha J. Williams | Executive Vice President, Electric Operations | June 1, 2011 to present | ||||
Senior Vice President, Energy Delivery | December 1, 2007 to May 31, 2011 | |||||
Vice President, Power Systems, Distribution, Florida Power and Light Company | July 2003 to July 2007 | |||||
Karen A. Austin | Senior Vice President and Chief | |||||
President, Consumer Electronics, Sears Holdings | February 2009 to May 2011 | |||||
Executive Vice President, Chief Information Officer, Sears Holdings | March 2005 to January 2009 | |||||
Desmond A. Bell | Senior Vice President, | |||||
Senior Vice President, Shared Services and Chief Procurement Officer | October 1, 2008 to | |||||
Vice President, Shared Services and Chief Procurement Officer | March 1, 2008 to September 30, 2008 | |||||
Vice President and Chief of Staff | March 19, 2007 to February 29, 2008 | |||||
Vice President, Parts Logistics, Bombardier Aerospace | April 2003 to September 2006 | |||||
Thomas E. Bottorff | Senior Vice President, Regulatory Relations | October 14, 2005 to present | ||||
Helen A. Burt | Senior Vice President and Chief Customer Officer | February 27, 2006 to present | ||||
John T. Conway | Senior Vice President, Energy Supply and Chief Nuclear Officer | April 1, 2009 to present | ||||
Senior Vice President, Generation and Chief Nuclear Officer | October 1, | |||||
Senior Vice President and Chief Nuclear Officer | March 1, 2008 to September 30, 2008 | |||||
Site Vice President, Diablo Canyon Power Plant | May | |||||
Site Vice President, Monticello Nuclear Plant, Nuclear Management Company | May 2005 to | |||||
Senior Vice President, | ||||||
Senior Vice President and Chief | ||||||
Senior Vice President | ||||||
Hyun Park | Senior Vice President and General Counsel, PG&E Corporation | November 13, 2006 to present | ||||
Greg S. Pruett | Senior Vice President, | November 1, 2009 to present | ||||
Senior Vice President, Corporate Affairs, PG&E Corporation | November 1, 2009 to present | |||||
Senior Vice President, Corporate Relations | March | |||||
Senior Vice President, Corporate Relations, PG&E Corporation | November 1, 2007 to | |||||
Vice President, Corporate Relations, PG&E Corporation | March 1, 2007 to October 31, 2007 | |||||
Vice President, Communications and Marketing, American Gas Association | April 10, 2006 to February 23, 2007 | |||||
John R. Simon | Senior Vice President, Human Resources | April 16, 2007 to present | ||||
Senior Vice President, Human Resources, PG&E Corporation | April 16, 2007 to present | |||||
Executive Vice President, Global Human Capital, TeleTech | March 21, 2006 to April 13, 2007 | |||||
Fong Wan | Senior Vice President, Energy Procurement | October 1, 2008 to present | ||||
Vice President, Energy Procurement | January 9, 2006 to September 30, 2008 |
Name | Position | Period Held Office | ||
Dinyar B. Mistry | Vice President, | |||
Vice President | ||||
Vice President | ||||
Vice President | September 16, 2009 to March | |||
Vice President | ||||
Vice President, | ||||
Vice President, Regulation and Rates | September 20, 2007 to December 31, 2008 | |||
Vice President, State Regulation | November 9, 2005 to September 19, 2007 |
As of February 20, 2009,7, 2012, there were 85,65871,943 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York Stock Exchange and the Swiss stock exchanges. The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth under the heading “Quarterly Consolidated Financial Data (Unaudited)” in the 20082011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. Shares of common stock of the Utility are not listed but are solely owned by PG&E Corporation. Information about the frequency, amount, and amountrestrictions upon the payment of, dividends on common stock paiddeclared by PG&E Corporation and the Utility is set forthappears in the table entitled “Selected2011 Annual Report in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, in Note 6: Common Stock and Share-based Compensation–Dividends, of the Notes to the Consolidated Financial Data”Statements, and in the 2008 Annual Report,section of MD&A entitled “Liquidity and Financial Resources—Dividends,” which information is incorporated by reference and included in Exhibit 13 to this report. The discussion
Sales of dividends with respect to PG&E Corporation's and the Utility’s common stock is set forth under the section of MD&A entitled “Liquidity and Financial Resources — Dividends” in the 2008 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
During the quarter ended December 31, 2008,2011, PG&E Corporation made equity contributions totaling $180$205 million to the Utility in order to maintain the Utility’s 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures.
During the quarter ended December 31, 2011, PG&E Corporation did not redeem or repurchase any shares of common stock:
Period | Total Number of Shares Purchased | Average Price Paid Per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs | |||||||
October 1 through October 31, 2008 | - | $ | - | $ | - | ||||||
November 1 through November 30, 2008 | - | $ | - | $ | - | ||||||
December 1 through December 31, 2008 | 3,872 | (1) | $ | $38.71 | - | $ | - | ||||
Total | 3,872 | $ | $38.71 | - | $ | - | |||||
(1) Shares tendered to satisfy tax withholding obligations arising upon the vesting of PG&E Corporation restricted stock. |
A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Companythe Utility for each of the last five fiscal years, is set forth under the heading “Selected Financial Data” in the 20082011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
Item 7.Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations
A discussion of PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company'sthe Utility’s consolidated financial condition and results of operations is set forth under the heading “Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 20082011 Annual Report, which discussion is incorporated by reference and included in Exhibit 13 to this report.
Information responding to Item 7A appears in the 20082011 Annual Report under the heading “Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities,” and under Notes 2,10 and 11 and 12 of the Notes to the Consolidated Financial Statements of the 20082011 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.
Information responding to Item 8 appears in the 20082011 Annual Report under the following headings for PG&E Corporation: “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders' Equity;” under the following headings for Pacific Gas and Electric Company: “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders'Shareholders’ Equity;” and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” and “Report of Independent Registered Public Accounting Firm,” which information is incorporated by reference and included in Exhibit 13 to this report.
Not applicable.
Based on an evaluation of PG&E Corporation'sCorporation’s and the Utility'sUtility’s disclosure controls and procedures as of December 31, 2008,2011, PG&E Corporation'sCorporation’s and the Utility'sUtility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the Securities Exchange1934 Act of 1934 (“1934 Act”) is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation'sCorporation’s and the Utility'sUtility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation'sCorporation’s and the Utility'sUtility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 20082011 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation'sCorporation’s or the Utility'sUtility’s internal control over financial reporting.
Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management'sManagement’s report, together with the report of the independent registered public accounting firm, appears in the 20082011 Annual Report under the heading “Management's“Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm,” which information is incorporated by reference and included in Exhibit 13 to this report.
Not applicable.
PART III
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Companythe Utility is included above in a separate item captioned “Executive Officers of the Registrants” at the end of Part I of this report. Other information responding to Item 10regarding directors is included under the heading “Item No. 1: Election of“Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company” andin the Joint Proxy Statement relating to the 2012 Annual Meetings of Shareholders, which information is hereby incorporated by reference. Information regarding compliance with Section 16 of the Exchange Act is included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 20092012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Website Availability of Code of Ethics, Corporate Governance and Other Documents
The following documents are available both on PG&E Corporation'sCorporation’s websitewww.pgecorp.com,, and Pacific Gas and Electric Company'sthe Utility’s website,www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Companythe Utility applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporation'sCorporation’s and Pacific Gas and Electric Company'sthe Utility’s corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies'companies’ Audit Committees and the PG&E Corporation Nominating and Governance Committee and Compensation Committee. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Vice President, Corporate Governance and Corporate Secretary of PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.
If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Companythe Utility that apply to their respective Chief Executive Officers, Chief Financial Officers, or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within 4four business days of the waiver.
Procedures for Shareholder Recommendations of Nominees to the Boards of Directors
During 20082011 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy
Audit Committees and Audit Committee Financial Expert
Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Corporate Governance – Board Committee Duties and Composition – Audit Committees” and “Corporate Governance – Board Committee Duties and Composition – Committee Membership Requirements” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company Board Committees Audit Committees”– Committee Membership” in the Joint Proxy Statement relating to the 20092012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company,the Utility, is included under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - 2008,2011,” “Grants of Plan-basedPlan-Based Awards in 2008,2011,” “Outstanding Equity Awards at Fiscal Year End - 2008,2011,” “Option Exercises and Stock Vested During 2008,2011,” “Pension Benefits – 2008,2011,” “Non-Qualified Deferred Compensation – 2011,” “Compensation of Non-Employee Directors,” and “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “2011 Director Compensation” in the Joint Proxy Statement relating to the 20092012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information responding to Item 12,regarding the beneficial ownership of securities for each of PG&E Corporation and Pacific Gas and Electric Company,the Utility, is included under the heading “Security Ownership of Management” and under the heading “Principal“Other Information - Principal Shareholders” in the Joint Proxy Statement relating to the 20092012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 20082011 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation'sCorporation’s existing equity compensation plans.
Plan Category | (a) Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights | (b) Weighted Average Exercise Price of Outstanding Options, Warrants and Rights | (c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column(a)) | |||
Equity compensation plans approved by shareholders | $ | |||||
Equity compensation plans not approved by shareholders | ||||||
Total equity compensation plans | $ |
(1) |
(2) |
Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company,the Utility, is included under the headings “Related Person Transactions,” “Review, Approval, and Ratification of Related PersonParty Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company – Director Independence”Independence and Qualifications” in the Joint Proxy Statement relating to the 20092012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
Information responding to Item 14, for each of PG&E Corporation and Pacific Gas and Electric Company,the Utility, is included under the heading “Information Regarding the Independent Registered Public Accounting Firm offor PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 20092012 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
(a) | The following documents are filed as a part of this report: |
1. The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are contained in the 20082011 Annual Report and are incorporated by reference in this report:
Consolidated Statements of Income for the Years Ended December 31, 2008, 2007,2011, 2010, and 20062009 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 20082011 and 20072010 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007,2011, 2010, and 20062009 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2008, 2007,2011, 2010, and 20062009 for eachPG&E Corporation.
Consolidated Statements of PG&E CorporationShareholders’ Equity for the Years Ended December 31, 2011, 2010, and 2009 for Pacific Gas and Electric Company.
Notes to the Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
2. The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:
Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
I—Condensed Financial Information of Parent as of December 31, 20082011 and 20072010 and for the Years Ended December 31, 2008, 2007,2011, 2010, and 2006.
II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2008, 2007,2011, 2010, and 2006.
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto.
3. Exhibits required by Item 601 of Regulation S-K:
Exhibit Number | Exhibit Description | |
2.1 | Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric | |
2.2 | Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric | |
3.1 | Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E | |
3.2 | Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E | |
3.3 | Bylaws of PG&E Corporation amended as of | |
3.4 | Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric | |
3.5 | Bylaws of Pacific Gas and Electric Company amended as of | |
4.1 | Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric | |
4.2 | First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s | |
4.3 | Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, | |
4.4 | Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s | |
4.5 | Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s | |
4.6 | Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1) |
Exhibit Number | Exhibit Description | |
4.7 | Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1) | |
4.8 | Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1) | |
4.9 | Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1) | |
4.10 | Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1) | |
4.11 | Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1) | |
4.12 | Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.13 | Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.14 | Fifteenth Supplemental Indenture dated as of November 22, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 22, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.15 | Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.16 | Senior Note Indenture related to PG&E | |
4.17 |
Exhibit Number | Exhibit Description | ||
10.1 | Credit Agreement, | ||
10.2 | Credit Agreement, dated May 31, 2011, among (1) Pacific Gas and | ||
10.3 | Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E | ||
10.4 | Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8) | ||
10.5 | Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9) | ||
10.6 * | Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4) | ||
10.7 * | Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11) | ||
10.8 * | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) | ||
10.9 * | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) | ||
10.10 * | Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.3) |
Exhibit Number | Exhibit Description | |
10.11 * | Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1) | |
10.12 * | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011(incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2) | |
10.13 * | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3) | |
10.14 * | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4) | |
10.15 * | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5) | |
10.16 * | Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4) | |
10.17 * | Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.18) | |
10.18 * | Separation Agreement between PG&E Corporation and Rand S. Rosenberg dated October 31, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.6) | |
10.19 * | Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.18) | |
10.20 * | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21) | |
10.21 * | Severance Agreement between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.5) | |
10.22 * | Settlement Agreement and Release between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.6) | |
10.23 * | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7) | |
10.24 * | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8) | |
10.25 * | Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.18) |
Exhibit Number | Exhibit Description | ||
10.26 * | Separation Agreement between Pacific Gas and Electric Company and Edward Salas, as approved by the PG&E Corporation Compensation Committee on June 14, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.12) | ||
10.27 * | PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10) | ||
10.28 * | PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, | ||
10.29 * | |||
PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24) | |||
10.30 * | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, | ||
10.31 * | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, | ||
10.32 * | Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27) | ||
10.33 * | Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28) | ||
10.34 * | PG&E Corporation Supplemental Executive Retirement Plan, | ||
10.35 * | Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30) | ||
10.36 * | Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric | ||
10.37 * | Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32) | ||
10.38 * | PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 |
Exhibit Number | Exhibit Description | ||
10.39 * | Resolution of the PG&E Corporation Board of Directors dated | ||
10.40 * | Resolution of the Pacific Gas and Electric Company Board of Directors dated | ||
10.41 * | |||
PG&E Corporation 2006 Long-Term Incentive Plan, as amended through | |||
10.42 * | PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E | ||
10.43 * | |||
Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E | |||
10.44 * | Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E | ||
10.45 * | Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 | ||
10.46 * | Form of Restricted Stock Unit Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No.��1-12609), Exhibit 10.2) | ||
10.47 * | Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2) | ||
10.48 * | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1) | ||
10.49 * | Form of Restricted Stock Unit Agreement for 2011 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.9) | ||
10.50 * | Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric | ||
10.51 * | |||
Form of Performance Share Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E | |||
10.52 * | |||
Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.53) | |||
10.53 * | Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.3) |
Exhibit Number | Exhibit Description | ||
10.54 * | Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3) | ||
10.55 * | Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.2) | ||
10.56 * | PG&E Corporation 2010 Executive Stock Ownership | ||
10.57 * | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E | ||
10.58 * | PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.56) | ||
10.59 * | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51) | ||
10.60 * | PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E | ||
10.61 * | Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58) | ||
10.62 * | PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E | ||
10.63 * | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E | ||
10.64 * | PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54) | ||
10.65 * | Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E | ||
10.66 * | Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41) | ||
12.1 | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company | ||
12.2 | Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company | ||
12.3 | Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation |
Exhibit Number | Exhibit Description | |
13 | The following portions of the | |
21 | Subsidiaries of the Registrant | |
23 | Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP) | |
24.1 | Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K | |
24.2 | Powers of Attorney | |
31.1 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002 | |
31.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002 | |
**32.1 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 | |
**32.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 | |
101.INS | XBRL Instance Document | |
101.SCH | XBRL Taxonomy Extension Schema Document | |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.LAB | XBRL Taxonomy Extension Labels Linkbase Document | |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | |
* | Management contract or compensatory agreement. | |
** | Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report. |
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 20082011 to be signed on their behalf by the undersigned, thereunto duly authorized.
PG&E CORPORATION | PACIFIC GAS AND ELECTRIC COMPANY | ||||||||
(Registrant) * | (Registrant) *CHRISTOPHER P. JOHNS | ||||||||
Anthony F. Earley, Jr. | Christopher P. Johns | ||||||||
By: | Chairman of the Board, Chief Executive Officer, and President | ||||||||
By: | President | ||||||||
Date: | February 16, 2012 | Date: | February 16, 2012 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.
Signature | Title | Date | |||||||
A. Principal Executive Officers | |||||||||
* ANTHONY F. EARLEY, JR. | Chairman of the Board, Chief Executive Officer, and President | February | |||||||
| |||||||||
*CHRISTOPHER P. JOHNS | |||||||||
President (Pacific Gas and Electric Company) | February | ||||||||
Christopher P. Johns | |||||||||
B. Principal Financial Officers | |||||||||
*KENT M. HARVEY | Senior Vice President, Treasurer (PG&E Corporation) | February | |||||||
| |||||||||
*DINYAR B. MISTRY | Vice President, Chief Financial Officer, and Controller | February 16, 2012 | |||||||
Dinyar B. Mistry | (Pacific Gas and Electric Company) | ||||||||
C. Principal Accounting Officer | |||||||||
*DINYAR B. MISTRY | Vice President and Controller (PG&E | February 16, 2012 | |||||||
Dinyar B. Mistry | Vice President, Chief Financial Officer, and (Pacific Gas and Electric Company) | ||||||||
D. Directors | |||||||||
*DAVID R. ANDREWS | Director | February | |||||||
David R. Andrews(1) | |||||||||
(1) | Mr. Andrews’ power of attorney authorizes Mr. Park to sign for Mr. Andrews only in his capacity as a director of PG&E Corporation. |
*LEWIS CHEW | Director | February | ||||||
Lewis Chew |
*C. LEE COX | Director | February 16, 2012 | |||||||
C. Lee Cox | |||||||||
*ANTHONY F. EARLEY, JR. | Director (PG&E Corporation only) | February 16, 2012 | |||||||
Anthony F. Earley, Jr. | |||||||||
*MARYELLEN C. HERRINGER | Director | February | |||||||
Maryellen C. Herringer | |||||||||
*CHRISTOPHER P. JOHNS | Director (Pacific Gas and Electric Company only) | February 16, 2012 | |||||||
Christopher P. Johns | |||||||||
*ROGER H. KIMMEL | Director | February | |||||||
Roger H. Kimmel | |||||||||
*RICHARD A. MESERVE | Director | February | |||||||
Richard A. Meserve | |||||||||
*FORREST E. MILLER | Director | February | |||||||
| |||||||||
*ROSENDO G. PARRA | Director | ||||||||
February 16, 2012 | |||||||||
Rosendo G. Parra | |||||||||
*BARBARA L. RAMBO | Director | February | |||||||
Barbara L. Rambo | |||||||||
*BARRY LAWSON WILLIAMS | Director | February | |||||||
Barry Lawson Williams | |||||||||
*By: | HYUN PARK | |||||
HYUN PARK, Attorney-in-Fact |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company
San Francisco, California
We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the “Company”) and Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 20082011 and 2007,2010, and for each of the three years in the period ended December 31, 2008,2011, and the Company’s and the Utility’s internal control over financial reporting as of December 31, 2008,2011, and have issued our report thereon dated February 19, 200916, 2012 (which report expresses an unqualified opinion and includes for the Company and Utility an explanatory paragraph statingrelating to several investigations and enforcement matters pending with the California Public Utilities Commission that may result in January 2008 new accounting standards were adopted for addressing fair value measurement and an amendment to an interpretationmaterial amounts of accounting standards for offsetting amounts related to certain contracts, in 2007 a new interpretation of accounting standards for uncertainty in income taxes, and in 2006 new accounting standards for defined benefit pensions and other postretirement plans and share-based payments)penalties); such consolidated financial statements and our report are included in your 20082011 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the consolidated financial statement schedules of the Company and Utility listed in Item 15(a)2. These consolidated financial statement schedules are the responsibility of the Company’s and the Utility’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
February 19, 2009
San Francisco, CA
PG&E CORPORATION
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME
(in millions, except per share amounts)
Year Ended December 31, | |||
2008 | 2007 | 2006 | |
Administrative service revenue | 119 | 102 | 110 |
Equity in earnings of subsidiaries | 1,182 | 1,006 | 964 |
Operating expenses | (105) | (112) | (115) |
Interest income | 4 | 15 | 15 |
Interest expense | (30) | (31) | (30) |
Other income (expense) | (46) | (6) | (1) |
Income before income taxes | 1,124 | 974 | 943 |
Income tax benefit | 60 | 32 | 48 |
Income from continuing operations | 1,184 | 1,006 | 991 |
Gain on disposal of NEGT | 154 | - | - |
Net income before intercompany eliminations | 1,338 | 1,006 | 991 |
Weighted average common shares outstanding, basic | 357 | 351 | 346 |
Weighted average common shares outstanding, diluted | 358 | 353 | 349 |
Earnings per common share, basic(1) | $3.64 | $2.79 | $2.78 |
Earnings per common share, diluted(1) | $3.63 | $2.78 | $2.76 |
september 30 | september 30 | september 30 | ||||||||||
Year Ended December 31, | ||||||||||||
2011 | 2010 | 2009 | ||||||||||
Administrative service revenue | $ 44 | $ 53 | $ 59 | |||||||||
Operating expenses | (44) | (55) | (61) | |||||||||
Interest income | 1 | 1 | 1 | |||||||||
Interest expense | (22) | (35) | (43) | |||||||||
Other income (expense) | (17) | 4 | 11 | |||||||||
Equity in earnings of subsidiaries | 852 | 1,105 | 1,231 | |||||||||
|
|
|
|
|
| |||||||
Income before income taxes | 814 | 1,073 | 1,198 | |||||||||
Income tax benefit | 30 | 26 | 22 | |||||||||
|
|
|
|
|
| |||||||
Income Available for Common Shareholders | $ 844 | $ 1,099 | $ 1,220 | |||||||||
|
|
|
|
|
| |||||||
Weighted average common shares outstanding, basic | 401 | 382 | 368 | |||||||||
|
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|
|
| |||||||
Weighted average common shares outstanding, diluted | 402 | 392 | 386 | |||||||||
|
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| |||||||
Earnings per common share, basic | $ 2.10 | $ 2.86 | $ 3.25 | |||||||||
|
|
|
|
|
| |||||||
Earnings per common share, diluted | $ 2.10 | $ 2.82 | $ 3.20 | |||||||||
|
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|
|
|
In calculating diluted EPS during the period PG&E Corporation’s Convertible Subordinated Notes were outstanding, PG&E Corporation adoptedapplied the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and“if-converted” method to reflect the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified bydilutive effect of the Financial Accounting Standards Board on March 31, 2004.
PG&E CORPORATION
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT – —(Continued)
CONDENSED BALANCE SHEETS
(in millions)
Balance at December 31, | ||
2008 | 2007 | |
ASSETS | ||
Current Assets: | ||
Cash and cash equivalents | $ 167 | $ 204 |
Advances to affiliates | 28 | 30 |
Income taxes receivable | 148 | 46 |
Other current assets | 14 | 3 |
Total current assets | 357 | 283 |
Equipment | 17 | 17 |
Accumulated depreciation | (15) | (15) |
Net equipment | 2 | 2 |
Investments in subsidiaries | 9,539 | 8,886 |
Other investments | 68 | 87 |
Deferred income taxes | 51 | 51 |
Other | 4 | 9 |
Total Assets | $ 10,021 | $ 9,318 |
LIABILITIES AND SHAREHOLDERS' EQUITY | ||
Current Liabilities: | ||
Accounts payable—related parties | $ 34 | $ 40 |
Accounts payable—other | 18 | 24 |
Other | 189 | 174 |
Total current liabilities | 241 | 238 |
Noncurrent Liabilities: | ||
Long-term debt | 280 | 280 |
Income taxes payable | 23 | 131 |
Other | 100 | 116 |
Total noncurrent liabilities | 403 | 527 |
Common Shareholders' Equity | ||
Common stock | 5,984 | 6,110 |
Common stock held by subsidiary | - | (718) |
Reinvested earnings | 3,614 | 3,151 |
Accumulated other comprehensive income | (221) | 10 |
Total common shareholders' equity | 9,377 | 8,553 |
Total Liabilities and Shareholders' Equity | $ 10,021 | $ 9,318 |
september 30 | september 30 | |||||||
Balance at December 31, | ||||||||
2011 | 2010 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ 209 | $ 240 | ||||||
Advances to affiliates | 18 | 25 | ||||||
Income taxes receivable | 8 | 1 | ||||||
Deferred income taxes | 4 | 5 | ||||||
|
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|
| |||||
Total current assets | 239 | 271 | ||||||
|
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|
| |||||
Noncurrent Assets | ||||||||
Equipment | 14 | 14 | ||||||
Accumulated depreciation | (14) | (14) | ||||||
|
|
|
| |||||
Net equipment | – | – | ||||||
Investments in subsidiaries | 12,378 | 11,618 | ||||||
Other investments | 94 | 89 | ||||||
Income taxes receivable | 2 | – | ||||||
Deferred income taxes | 143 | 116 | ||||||
Other | 2 | 2 | ||||||
|
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|
| |||||
Total noncurrent assets | 12,619 | 11,825 | ||||||
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| |||||
Total Assets | $ 12,858 | $ 12,096 | ||||||
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| |||||
LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable – related parties | $ – | $ 106 | ||||||
Accounts payable – other | 21 | 3 | ||||||
Income taxes payable | 57 | 1 | ||||||
Other | 208 | 213 | ||||||
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| |||||
Total current liabilities | 286 | 323 | ||||||
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| |||||
Noncurrent Liabilities | ||||||||
Long-term debt | 349 | 349 | ||||||
Income taxes payable | 3 | 48 | ||||||
Other | 119 | 94 | ||||||
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Total noncurrent liabilities | 471 | 491 | ||||||
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Common Shareholders’ Equity | ||||||||
Common stock | 7,602 | 6,878 | ||||||
Reinvested earnings | 4,712 | 4,606 | ||||||
Accumulated other comprehensive loss | (213) | (202) | ||||||
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| |||||
Total common shareholders’ equity | 12,101 | 11,282 | ||||||
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Total Liabilities and Shareholders’ Equity | $ 12,858 | $ 12,096 | ||||||
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PG&E CORPORATION
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
Year Ended December 31, | ||||||||||
2008 | 2007 | 2006 | ||||||||
Cash Flows from Operating Activities: | ||||||||||
Net income | $ | 1,338 | $ | 1,006 | $ | 991 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||
Depreciation and amortization | 3 | 1 | - | |||||||
Equity in earnings of subsidiaries | (1,180) | (1,006) | (964) | |||||||
Noncurrent income taxes receivable/payable | (108) | 4 | - | |||||||
Other | (81) ) | (19) ) | 132 | |||||||
Net cash used in operating activities | (28) | 24 | 159 | |||||||
Cash Flows From Investing Activities: | ||||||||||
Capital expenditures | - | (1) | (1) | |||||||
Investment in subsidiaries | (275) | (405) | - | |||||||
Dividends received from subsidiaries | 596 | 509 | 460 | |||||||
Other | (12) | - | - | |||||||
Net cash provided by investing activities | 309 | 103 | 459 | |||||||
Cash Flows From Financing Activities(1): | ||||||||||
Common stock issued | 225 | 175 | 131 | |||||||
Common stock repurchased | - | - | (114) | |||||||
Common stock dividends paid | (546) | (496) | (456) | |||||||
Other | 2 | 12 | (43) | |||||||
Net cash used in financing activities | (319) | (309) | (482) | |||||||
Net change in cash and cash equivalents | (38) | (182) | 136 | |||||||
Cash and cash equivalents at January 1 | 204 | 386 | 250 | |||||||
Cash and cash equivalents at December 31 | $ | 166 | $ | 204 | $ | 386 | ||||
(1) On January 15, 2008, PG&E Corporation paid a quarterly common stock dividend of $0.36 per share. On April 15, July 15, and October 15, 2008, PG&E Corporation paid quarterly common stock dividends of $0.39 per share. Of the total dividend payments made by PG&E Corporation in 2008, approximately $28 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. On January 15, 2007, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share. On April 15, July 15, and October 15, 2007, PG&E Corporation paid quarterly common stock dividends of $0.36 per share. Of the total dividend payments made by PG&E Corporation in 2007, approximately $35 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. On January 16, April 15, July 15, and October 15, 2006, PG&E Corporation paid a quarterly common stock dividend of $0.33 per share, totaling approximately $489 million. Of the total dividend payments made by PG&E Corporation in 2006, approximately $33 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation. |
september 30 | september 30 | september 30 | september 30 | |||||||||||
Year Ended December 31, | ||||||||||||||
2011 | 2010 | 2009 | ||||||||||||
Cash Flows from Operating Activities: | ||||||||||||||
Net income | $ | 844 | $ | 1,099 | $ | 1,220 | ||||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||||
Depreciation and amortization | 36 | 38 | 20 | |||||||||||
Equity in earnings of subsidiaries | (852) | (1,105) | (1,231) | |||||||||||
Deferred income taxes and tax credits, net | (26) | 19 | – | |||||||||||
Noncurrent income taxes receivable/payable | (47) | 34 | (9) | |||||||||||
Current income taxes receivable/payable | 49 | (1) | 148 | |||||||||||
Other | (80) | (50) | (13) | |||||||||||
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Net cash provided by (used in) operating activities | (76) | 34 | 135 | |||||||||||
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Cash Flows From Investing Activities: | ||||||||||||||
Investment in subsidiaries | (759) | (347) | (721) | |||||||||||
Dividends received from subsidiaries(1) | 716 | 716 | 624 | |||||||||||
Proceeds from tax equity investments | 129 | 7 | – | |||||||||||
Other | – | (4) | 10 | |||||||||||
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Net cash provided by (used in) investing activities | 86 | 372 | (87) | |||||||||||
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Cash Flows From Financing Activities: | ||||||||||||||
Borrowings under revolving credit facilities | 150 | 90 | – | |||||||||||
Repayments under revolving credit facilities | (150) | (90) | – | |||||||||||
Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2009 | – | – | 348 | |||||||||||
Common stock issued | 662 | 303 | 219 | |||||||||||
Common stock dividends paid(2) | (704) | (662) | (590) | |||||||||||
Other | 1 | – | 1 | |||||||||||
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Net cash used in financing activities | (41) | (359) | (22) | |||||||||||
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Net change in cash and cash equivalents | (31) | 47 | 26 | |||||||||||
Cash and cash equivalents at January 1 | 240 | 193 | 167 | |||||||||||
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Cash and cash equivalents at December 31 | $ | 209 | $ | 240 | $ | 193 | ||||||||
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(1) | Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an investing cash flow. |
(2) | On January 15, April 15, July 15, October 15, 2011, PG&E Corporation paid quarterly common stock dividends of $0.455 per share. |
On January 15, 2010, PG&E Corporation
On January 15, 2009, PG&E Corporation paid a quarterly common stock dividend of $0.39 per share. On April 15, July 15, and October 15, 2009, PG&E Corporation paid quarterly common stock dividends of $0.42 per share.
PG&E Corporation
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2008, 2007,2011, 2010, and 2006
Additions | |||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(3) | Balance at End of Period |
(in millions) | |||||
Valuation and qualifying accounts deducted from assets: | |||||
2008: | |||||
Allowance for uncollectible accounts(1)(2) | $ 58 | $ 68 | $ 11 | $ 61 | $ 76 |
2007: | |||||
Allowance for uncollectible accounts(1)(2) | $ 50 | $ 20 | $ - | $ 12 | $ 58 |
2006: | |||||
Allowance for uncollectible accounts(1)(2) | $ 77 | $ 2 | $ - | $ 29 | $ 50 |
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.” | |||||
(2) Allowance for uncollectible accounts does not include NEGT. | |||||
(3) Deductions consist principally of write-offs, net of collections of receivables previously written off. |
(in millions)
september 30000 | september 30000 | september 30000 | september 30000 | september 30000 | ||||||||||||||||
Additions | ||||||||||||||||||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions (2) | Balance at End of Period | |||||||||||||||
Valuation and qualifying accounts deducted from assets: | ||||||||||||||||||||
2011: | ||||||||||||||||||||
Allowance for uncollectible accounts(1) | $ 81 | $ 60 | $ - | $ 60 | $ 81 | |||||||||||||||
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2010: | ||||||||||||||||||||
Allowance for uncollectible accounts(1) | $ 68 | $ 56 | $ - | $ 43 | $ 81 | |||||||||||||||
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2009: | ||||||||||||||||||||
Allowance for uncollectible accounts(1) | $ 76 | $ 68 | $ - | $ 76 | $ 68 | |||||||||||||||
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(1) | Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers.” |
(2) | Deductions consist principally of write-offs, net of collections of receivables previously written off. |
Pacific Gas and Electric Company
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2008, 2007,2011, 2010, and 2006
Additions | |||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(2) | Balance at End of Period |
(in millions) | |||||
Valuation and qualifying accounts deducted from assets: | |||||
2008: | |||||
Allowance for uncollectible accounts(1) | $ 58 | $ 68 | $ 11 | $ 61 | $ 76 |
2007: | |||||
Allowance for uncollectible accounts(1) | $ 50 | $ 20 | $ - | $ 12 | $ 58 |
2006: | |||||
Allowance for uncollectible accounts(1) | $ 77 | $ 2 | $ - | $ 29 | $ 50 |
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable Customers, net.” | |||||
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off. |
(in millions)
september 30000 | september 30000 | september 30000 | september 30000 | september 30000 | ||||||||||||||||
Additions | ||||||||||||||||||||
Description | Balance at Beginning of Period | Charged to Costs and Expenses | Charged to Other Accounts | Deductions(2) | Balance at End of Period | |||||||||||||||
Valuation and qualifying accounts deducted from assets: | ||||||||||||||||||||
2011: | ||||||||||||||||||||
Allowance for uncollectible accounts(1) | $ 81 | $ 60 | $ - | $ 60 | $ 81 | |||||||||||||||
2010: | ||||||||||||||||||||
Allowance for uncollectible accounts(1) | $ 68 | $ 56 | $ - | $ 43 | $ 81 | |||||||||||||||
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2009: | ||||||||||||||||||||
Allowance for uncollectible accounts(1) | $ 76 | $ 68 | $ - | $ 76 | $ 68 | |||||||||||||||
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(1) | Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers.” |
(2) | Deductions consist principally of write-offs, net of collections of receivables previously written off. |
EXHIBIT INDEX
Exhibit Number | Exhibit Description | |
2.1 | Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric | |
2.2 | Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric | |
3.1 | Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E | |
3.2 | Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E | |
3.3 | Bylaws of PG&E Corporation amended as of | |
3.4 | Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric | |
3.5 | Bylaws of Pacific Gas and Electric Company amended as of | |
4.1 | Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric | |
4.2 | First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s | |
4.3 | Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, | |
4.4 | Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s | |
4.5 | Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s |
Exhibit Number | Exhibit Description | |
4.6 | Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1) | |
4.7 | Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1) | |
4.8 | Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1) | |
4.9 | Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1) | |
4.10 | Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1) | |
4.11 | Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1) | |
4.12 | Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021. (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.13 | Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.14 | Fifteenth Supplemental Indenture dated as of November 22, 2011, relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due November 20, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 22, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.15 | Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1) | |
4.16 | Senior Note Indenture related to PG&E |
Exhibit Number | Exhibit Description | ||
4.17 | First Supplemental Indenture, | ||
10.1 | Credit Agreement, dated May 31, 2011, among (1) PG&E Corporation, as borrower, (2) Bank of America, N.A. as administrative agent and a lender, (3) Citibank, N.A., and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, and (4) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, and (5) the following other lenders: Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., UBS Loan Finance LLC, The Bank of New York Mellon, Banco Bilbao Vizcaya Argentaria S.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and East West Bank (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended | ||
10.2 | |||
10.3 | Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E | ||
10.4 | Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8) | ||
10.5 | Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9) | ||
10.6 * | Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4) | ||
10.7 * | Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11) | ||
10.8 * | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) | ||
10.9 * | Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12) |
Exhibit Number | Exhibit Description | |
10.10 * | Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation dated May 12, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.3) | |
10.11 * | Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1) | |
10.12 * | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2) | |
10.13 * | Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3) | |
10.14 * | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4) | |
10.15 * | Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5) | |
10.16 * | Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4) | |
10.17 * | Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.18) | |
10.18 * | Separation Agreement between PG&E Corporation and Rand S. Rosenberg dated October 31, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.6) | |
10.19 * | Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.18) | |
10.20 * | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21) | |
10.21 * | Severance Agreement between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.5) | |
10.22 * | Settlement Agreement and Release between Pacific Gas and Electric Company and John S. Keenan dated April 5, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.6) | |
10.23 * | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7) | |
10.24 * | Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8) |
Exhibit Number | Exhibit Description | ||
10.25 * | Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.18) | ||
10.26 * | Separation Agreement between Pacific Gas and Electric Company and Edward Salas, as approved by the PG&E Corporation Compensation Committee on June 14, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.12) | ||
10.27 * | PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10) | ||
10.28 * | PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, | ||
10.29 * | |||
PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24) | |||
10.30 * | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, | ||
10.31 * | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, | ||
10.32 * | Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27) | ||
10.33 * | Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28) | ||
10.34 * | PG&E Corporation Supplemental Executive Retirement Plan, | ||
10.35 * | Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30) | ||
10.36 * | Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric | ||
10.37 * | Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32) |
Exhibit Number | Exhibit Description | ||
10.38 * | PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 | ||
10.39 * | Resolution of the PG&E Corporation Board of Directors dated | ||
10.40 * | Resolution of the Pacific Gas and Electric Company Board of Directors dated | ||
10.41 * | |||
PG&E Corporation 2006 Long-Term Incentive Plan, as amended through | |||
10.42 * | PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E | ||
10.43 * | |||
Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E | |||
10.44 * | Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E | ||
10.45 * | Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 | ||
10.46 * | Form of Restricted Stock Unit Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.2) | ||
10.47 * | Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2) | ||
10.48 * | Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1) | ||
10.49 * | Form of Restricted Stock Unit Agreement for 2011 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.9) | ||
10.50 * | Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric | ||
10.51 * | |||
Form of Performance Share Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E |
Exhibit Number | |||
10.52 * | |||
Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.53) | |||
10.53 * | Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.3) | ||
10.54 * | Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3) | ||
10.55 * | Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.2) | ||
10.56 * | PG&E Corporation 2010 Executive Stock Ownership | ||
10.57 * | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E | ||
10.58 * | PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.56) | ||
10.59 * | PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51) | ||
10.60 * | PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E | ||
10.61 * | Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58) | ||
10.62 * | PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E | ||
10.63 * | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E | ||
10.64 * | PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54) | ||
10.65 * | Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E | ||
10.66 * | Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41) | ||
12.1 | Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company |
Exhibit Number | Exhibit Description | |
12.2 | Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company | |
12.3 | Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation | |
13 | The following portions of the | |
21 | Subsidiaries of the Registrant | |
23 | Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP) | |
24.1 | Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K | |
24.2 | Powers of Attorney | |
31.1 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002 | |
31.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002 | |
**32.1 | Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002 | |
**32.2 | Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002 | |
101.INS | XBRL Instance Document | |
101.SCH | XBRL Taxonomy Extension Schema Document | |
101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | |
101.LAB | XBRL Taxonomy Extension Labels Linkbase Document | |
101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document | |
101.DEF | XBRL Taxonomy Extension Definition Linkbase Document |
* | Management contract or compensatory agreement. |
** | Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report. |